1
Commission File No. 1-1098
As filed with the Securities and Exchange Commission on March 11, 1994.
============================================================================
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
/X/ OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended DECEMBER 31, 1993
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
/ / For the Transition Period from ----- to -----
T H E C O L U M B I A G A S S Y S T E M, I N C.
------------------------------------------------------
(Exact name of registrant as specified in its charter)
Delaware 13-1594808
- ------------------------------------------------------------- ----------------------------------
(State or other Jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
20 Montchanin Road, Wilmington, Delaware 19807-0020
- ------------------------------------------------------------ ----------------------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (302) 429-5000
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
------------------- ---------------------
Common Stock, $10 Par Value . . . . . . . . . . . . . . . . . . . . New York Stock Exchange
Debentures
----------
9% Series due August 1993 7-1/2% Series due March 1997
9% Series due October 1994 7-1/2% Series due June 1997
8-3/4% Series due April 1995 7-1/2% Series due October 1997
9-1/8% Series due October 1995 7-1/2% Series due May 1998
10-1/8% Series due November 1995 10-1/4% Series due May 1999 New York Stock Exchange
8-3/8% Series due March 1996 9-7/8% Series due June 1999
9-1/8% Series due May 1996 10-1/4% Series due August 2011
8-1/4% Series due September 1996 10-1/2% Series due June 2012
Securities registered pursuant to Section 12(g) of the Act: None
SINCE JULY 31, 1991, THE COLUMBIA GAS SYSTEM, INC. AND ITS WHOLLY-OWNED
SUBSIDIARY COLUMBIA GAS TRANSMISSION CORPORATION HAVE BEEN OPERATING UNDER
BANKRUPTCY COURT PROTECTION PURSUANT TO CHAPTER 11 OF THE FEDERAL
BANKRUPTCY CODE.
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the proceeding 12 months (or for such shorter period that
the registrant was required to file such reports), and (2) has been subject
to such filing requirements for the past 90 days: Yes X or No .
-- --
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
The aggregate market value of the outstanding common shares of the
Registrant held by nonaffiliates as of February 28, 1994, was
$1,431,989,094. For purposes of the foregoing calculation, all directors
and/or officers have been deemed to be affiliates, but the registrant
disclaims that any of such directors and/or officers is an affiliate.
The number of shares outstanding of each class of common stock as of
February 28, 1994, was : Common Stock $10 Par Value: 50,559,225 shares
outstanding.
Documents Incorporated by Reference
Part III of this report incorporates by reference the Registrant's Proxy
Statement relating to the 1994 Annual Meeting of Stockholders.
1
2
CONTENTS
Page
Part I No.
----
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . 17
Part II
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters 17
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . 18
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations . . . . . . . . . . . . . . . . . . . . . 19
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . 53
Item 9. Change In and Disagreements with Accountants on Accounting and
Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . 112
Part III
Item 10. Directors and Executive Officers of the Registrant . . . . . . . . . 112
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . 113
Item 12. Security Ownership of Certain Beneficial Owners and Management . . . 113
Item 13. Certain Relationships and Related Transactions . . . . . . . . . . . 113
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . 113
Undertaking made in Connection with 1933 Act Compliance on Form S-8 . . . . . . . . . . 113
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115
2
3
PART I
ITEM 1. BUSINESS
General
The Columbia Gas System, Inc. (the Corporation) organized under the laws of
the State of Delaware on September 30, 1926, is a registered holding
company under the Public Utility Holding Company Act of 1935, as amended,
(1935 Act) and derives substantially all its revenues and earnings from the
operating results of its 19 direct subsidiaries. On July 31, 1991, the
Corporation and its wholly-owned subsidiary, Columbia Gas Transmission
Corporation (Columbia Transmission), filed separate petitions for
protection under Chapter 11 of the Federal Bankruptcy Code. Both the
Corporation and Columbia Transmission are debtors-in-possession under the
Bankruptcy Code and continue to operate their businesses in the normal
course subject to the jurisdiction of the United States Bankruptcy Court
for the District of Delaware. The Corporation owns all of the securities
of its subsidiaries except for approximately 10 percent of the stock in
Columbia LNG Corporation. The Corporation's subsidiaries are engaged in
exploration for and production of oil and natural gas, natural gas
transmission, natural gas distribution and other energy operations. In
addition, Columbia Gas System Service Corporation provides data processing,
financial, accounting, legal and other services for the Corporation and
other affiliates. The Corporation and its subsidiaries are sometimes
referred to herein as the System.
Oil and Gas Operations
The Corporation's oil and gas subsidiaries, Columbia Gas Development
Corporation and Columbia Natural Resources, Inc., explore for, develop,
produce, and market oil and natural gas in the United States. These
companies hold interests in more than two million net acres of gas and oil
leases and have proved oil and gas reserves in excess of 750 billion cubic
feet of gas equivalent.
Operations are focused in the Appalachian, Arkoma, Michigan, Permian,
Powder River and Williston basins; both onshore and offshore in the Gulf
Coast areas of Texas and Louisiana, and in Utah and California. Offshore
holdings include interests in federal blocks, most of which are located in
the West Cameron, Vermilion, Eugene Island, and Ship Shoal areas of the
Gulf of Mexico.
Transmission Operations
The Corporation's two interstate pipeline transmission companies, Columbia
Transmission and Columbia Gulf Transmission Company (Columbia Gulf),
operate a 23,700-mile pipeline network that extends from offshore in the
Gulf of Mexico to New York State and the eastern seaboard. In addition,
Columbia Transmission operates one of the nation's largest underground
storage systems.
Historically, Columbia Transmission offered both a wholesale sales service
and a transportation service to local distribution companies. However,
when a new federally mandated business restructuring of the industry took
effect in late 1993, Columbia Transmission expanded its transportation and
storage services for local distribution companies and industrial and
commercial customers and now provides only a minimal sales service.
Columbia Gulf's pipeline system, which extends from offshore Louisiana to
West Virginia, carries a major portion of the gas delivered by Columbia
Transmission. It also transports gas for third parties within the
production areas of the Gulf Coast. Columbia Gulf owns interests in the
Overthrust, Ozark and Trailblazer pipelines, which extend into major
midcontinent and western gas-producing areas. Combined, Columbia
Transmission and Columbia Gulf serve customers in 15 northeastern, middle
Atlantic, midwestern, and southern states and the District of Columbia.
Columbia LNG Corporation has announced plans to initiate peaking services
from its Cove Point LNG facility by the end of 1995.
Distribution Operations
The Corporation's five distribution subsidiaries provide natural gas
service to more than 1.9 million residential, commercial and industrial
customers in Ohio, Pennsylvania, Virginia, Kentucky, and Maryland. These
subsidiaries purchase gas supplies to serve their high-priority customers
and transport gas for industrial and commercial customers who purchase gas
from other sources. More than 28,000 miles of distribution pipelines serve
such major
3
4
ITEM 1. BUSINESS (Continued)
markets as Columbus, Lorain, Parma, Springfield, and Toledo in Ohio;
Gettysburg, York and a part of Pittsburgh in Pennsylvania; Lynchburg,
Staunton, Portsmouth and Richmond suburbs in Virginia; Ashland, Frankfort
and Lexington in Kentucky; and Cumberland and Hagerstown in Maryland.
Other Energy Operations
The Corporation's TriStar Ventures Corporation participates in natural
gas-fueled cogeneration projects that produce both electricity and useful
thermal energy.
Two subsidiaries, Columbia Propane Corporation and Commonwealth Propane,
Inc., sell propane at wholesale and retail to approximately 68,000
customers in six states.
In the Appalachian area, Columbia Coal Gasification Corporation another
subsidiary owns over 500 million tons of coal reserves, much of which
contains less than one percent sulfur. Approximately 50 percent of the
total reserves are leased to other companies for development.
Columbia Energy Services oversees the System's nonregulated natural gas
marketing efforts and provides an array of supply and fuel management
services to distribution companies, independent power producers and other
large end users both on and off the transmission and distribution
subsidiaries' pipeline systems.
Columbia Gas System Service Corporation provides centralized,
cost-efficient data processing, financial, accounting, legal, and other
services for the Corporation and other operating subsidiaries.
For additional discussion of the System's business segments, including
financial information for the last three fiscal years, see Item 7, page 19
through 52 and Note 16 on page 93 of Item 8.
Other Relevant Business Information
The System's customer base is broadly diversified, with no single customer
accounting for a significant portion of sales or transportation revenues.
The Corporation's operating subsidiaries are subject to competitive
pressures from other pipeline systems and producers that sell and/or
transport natural gas as well as from competition from alternative fuels,
primarily oil and electricity. The oil and gas subsidiaries compete in the
marketplace for sales of their oil and gas production through a combination
of long-term contracts and spot sales. The transportation subsidiaries
compete in the highly competitive northeast and midwest energy markets. The
distribution subsidiaries compete with alternative fuels and to a limited
extent with other gas companies.
Certain subsidiaries file reports with various federal agencies containing
estimates of company-owned oil and gas reserves. These estimates are
generally consistent but not always comparable to those reported in the
1993 Annual Report to Shareholders.
At January 31, 1994, the System had 10,114 full-time employees of which
2,089 are subject to collective bargaining agreements.
Information relating to environmental matters is detailed in Item 7 pages
33 through 34, page 41 and page 46 and in Item 8, Note 12H on pages 87
through 91.
For a listing of the subsidiaries of the Corporation and their lines of
business refer to Exhibit 22.
Public Utility Holding Company Act of 1935
The Corporation and its subsidiaries are subject, in certain matters, to
the jurisdiction of the Securities and Exchange Commission (SEC) under the
1935 Act. In 1944, the SEC held that the major portions of the System
complied with the requirements of Section 11 of the 1935 Act relating to a
"single integrated public-utility system" and businesses reasonably
incidental thereto, but the SEC reserved jurisdiction over the
retainability of certain subsidiaries.
4
5
ITEM 1. BUSINESS (Continued)
Included were two companies owning pipelines in West Virginia and Northern
Virginia extending into Maryland and New York (the reserved pipelines are
now part of Columbia Transmission) and Virginia Gas Distribution
Corporation (now a part of Commonwealth Gas Services, Inc.). Since that
time, the reservation of jurisdiction has been expanded to include the
subsequently acquired properties of Blue Ridge Gas Company (a Virginia
retail company which is now part of Commonwealth Gas Services, Inc.),
Commonwealth Gas Pipeline Corporation (now a part of Columbia Transmission)
and a retail subsidiary (Commonwealth Gas Services, Inc.) acquired as a
result of the merger of the Corporation with Commonwealth Natural
Resources, Inc. and Lynchburg Gas Company, (now a part of Commonwealth Gas
Services, Inc.).
The Corporation filed a motion with the SEC in June 1955 requesting the
termination of such reserved jurisdiction. After hearings, no further
action has been taken and the Corporation is unable to predict whether or
when the SEC will finally dispose of the Corporation's 1955 motion and
resolve the retainability issue.
The Gas Related Activities Act (GRAA), enacted in 1990, provides that gas
transmission is deemed to be reasonably incidental or economically
necessary or appropriate to the operation of the gas utility system under
Section 11 of the 1935 Act. Since the basis for questioning the
retainability of the gas transmission pipelines was compliance with this
Section 11 criteria, the passage of the GRAA supports, and should resolve,
the retainability of the gas transmission pipelines.
If however, any of these properties were ultimately to be held not
retainable, management believes that the SEC would permit the Corporation
to adopt a plan for orderly disposition which would permit full realization
of their intrinsic values.
ITEM 2. PROPERTIES
Information relating to properties of subsidiary companies is detailed on
pages 6 through 7 herein and pages 96 through 99 of Item 8 under Note 18.
The System also owns coal interests in the Appalachian area. Assets under
lien and other guarantees are described on page 86 in Note 12E of Item 8.
Neither the Corporation nor any subsidiary knows of material defects in the
title to any real properties of the subsidiaries of the Corporation or of
any material adverse claim of any right, title, or interest therein,
pending or contemplated except the Official Committee of Unsecured
Creditors of Columbia Transmission has filed a complaint which challenges
the 1990 property transfer from Columbia Transmission to Columbia Natural
Resources, Inc. as an alleged fraudulent transfer. Substantially all of
Columbia Transmission's property has been pledged to the Corporation as
security for First Mortgage Bonds issued by Columbia Transmission to the
Corporation which has also been challenged by the Official Committee of
Unsecured Creditors of Columbia Transmission.
5
6
ITEM 2. PROPERTIES (Continued)
OIL AND GAS DATA
Acreage - At December 31, 1993
Developed Acreage Undeveloped Acreage
--------------------------- ------------------------------
Gross Net Gross Net
--------- ------- ---------- -------
Appalachian . . . . . . . . . . . 1,621,593 1,559,920 731,413 561,361
Southwest - Onshore . . . . . . . 59,042 21,284 126,892 71,140
Southwest - Offshore . . . . . . 168,214 52,406 60,696 20,544
Rocky Mountain . . . . . . . . . 21,378 10,557 250,535 158,605
Other Areas . . . . . . . . . . . 1,034 168 2,914 353
----------- ---------- ----------- -----------
Total . . . . . . . . . . . 1,871,261 1,644,335 1,172,450 812,003
=========== ========== =========== ===========
Net Wells Completed - 12 Months Ended December 31
Exploratory Development Total
---------------------------- ----------------------------- ----------------------
Productive Dry Productive Dry Productive Dry
---------- --- ---------- --- ---------- -----
1993 . . . . 2 10 91 18 93(a) 28
1992 . . . . 9 14 37 7 46(a) 21
1991 . . . . 3 21 93 8 96(a) 29
Productive and Drilling Wells - At December 31, 1993
Production Wells
----------------------------------------------
Gross b Net Wells Drilling
-------- --------------- ---------------
Gas Oil Gas Oil Gross Net
------ ----- --- --- ----- ---
6,462 639 5,831 360 35 18
(a) Includes 17 net horizontal wells in 1993, 13 net horizontal wells in
1992 and 14 net horizontal wells in 1991.
(b) Includes 808 multiple completion gas wells and 8 multiple completion
oil wells, all of which are included as single wells in the table.
Also includes 46 gross productive horizontal wells.
6
7
ITEM 2. PROPERTIES (Continued)
GAS PROPERTIES OF SUBSIDIARIES - AS OF DECEMBER 31, 1993
Underground
Storage
------------------
Subsidiaries State Acreage Wells
------------------------------------------- ----- ------- -----
Columbia Gas of Kentucky, Inc. . . . . . . . . . . KY - -
Columbia Gas of Maryland, Inc. . . . . . . . . . . MD - -
Columbia Gas of Ohio, Inc. . . . . . . . . . . . . OH - -
Columbia Gas of Pennsylvania, Inc. . . . . . . . . PA 3,364 8
Commonwealth Gas Services, Inc. . . . . . . . . . . VA - -
Columbia Gas Transmission Corporation . . . . . . . DE - -
KY - -
MD 945 -
NJ - -
NY 25,838 143
NC - -
OH 482,058 2,459
PA 64,064 273
VA - -
WV 294,725 812
Columbia Gulf Transmission Company . . . . . . . . AR - -
KY - -
LA - -
MS - -
TN - -
TX - -
WY - -
Columbia Natural Resources, Inc. . . . . . . . . . KY - -
MI - -
NY - -
OH - -
PA - -
VA - -
WV - -
Columbia LNG Corporation . . . . . . . . . . . . . MD - -
VA - -
- -
Total . . . . . . . . . . . . . . . . . . . . . . . 870,994 3,695
======= =====
Miles of Pipeline Compressor Stations
---------------------------------------- -------------------
Gathering Installed
and Trans- Distri- Capacity
Subsidiaries Storage mission bution Number (hp)
------------------------------------------- --------- ------- ------- ------ ---------
Columbia Gas of Kentucky, Inc. . . . . . . . . . . - - 2,179 - -
Columbia Gas of Maryland, Inc. . . . . . . . . . . - - 570 - -
Columbia Gas of Ohio, Inc. . . . . . . . . . . . . - - 16,642 - -
Columbia Gas of Pennsylvania, Inc. . . . . . . . . 4 - 6,569 1 825
Commonwealth Gas Services, Inc. . . . . . . . . . . - - 3,369 - -
Columbia Gas Transmission Corporation . . . . . . . - 3 - - -
938 765 - 4 16,220
23 181 - - -
- 21 - - -
71 512 - 4 8,670
- 1 - 1 1,400
2,757 4,120 - 30 104,285
624 2,038 - 27 68,070
128 1,043 - 10 55,806
3,014 2,529 - 48 306,161
Columbia Gulf Transmission Company . . . . . . . . - 11 - - -
- 715 - 2 70,290
- 2,087 - 6 201,200
- 659 - 3 118,800
- 556 - 2 83,000
- 202 - - -
- 10 - - -
Columbia Natural Resources, Inc. . . . . . . . . . 432 - - - -
6 - - - -
2 - - - -
64 - - - -
6 - - - -
20 - - - -
122 - - - -
Columbia LNG Corporation . . . . . . . . . . . . . - 49 - - -
- 39 - - -
- -- - - -
Total . . . . . . . . . . . . . . . . . . . . . . . 8,211 15,541 29,329 138 1,034,727
===== ====== ====== === =========
NOTE: This table excludes minor gas properties and all construction work
in progress. The titles to the real properties of the
subsidiaries of the Corporation have not been examined for the
purpose of this document. Neither the Corporation nor any subsidiary
knows of material defects in the title to any of the real properties
of the subsidiaries of the Corporation or of any material adverse
claim of any right, title, or interest therein, pending or
contemplated except the Official Committee of Unsecured Creditors of
Columbia Transmission has filed a complaint which challenges the 1990
property transfer from Columbia Transmission to Columbia Natural
Resources, Inc. as an alleged fraudulent transfer. Substantially all
of Columbia Transmission's property has been pledged to the
Corporation as security for First Mortgage Bonds issued by Columbia
Transmission to the Corporation which has also been challenged by the
Official Committee of Unsecured Creditors of Columbia Transmission
7
8
ITEM 3. LEGAL PROCEEDINGS
I. Shareholder Class Actions and Derivative Suits (Unless otherwise
noted, all matters are stayed pursuant to Section 362 of the Bankruptcy
Code)
Since the June 19, 1991 announcement by the Board of Directors
regarding the Corporation's proposed charge to second quarter earnings and
suspension of its dividend, seventeen complaints including suits purporting
to be class actions, or alleging claims common to the purported class
actions, have been filed in the U.S. District Court for the District of
Delaware. These actions have been consolidated under the style In re
Columbia Gas Securities Litigation, Consol. C.A. No. 91-357. Although an
amended and consolidated complaint has yet to be filed, the preconsolidated
complaints variously named the Corporation, then current members of its
Board of Directors, certain officers, the Corporation's independent public
accountants, and the Corporation's underwriters for its 1990 common stock
offering as defendants (the Defendants).
These complaints generally allege the Defendants publicly made
material misleading statements during the relevant class periods (from
February 28, 1990 to June 19, 1991) concerning the Corporation's financial
condition, and failed to disclose material facts which rendered other
statements misleading, thereby artificially inflating the market price of
the Corporation's common stock and publicly traded debt securities, causing
the various plaintiffs and other class members to purchase such publicly
traded securities at artificially inflated prices. The complaints allege
violations of Sections 11, 12(2) and 15 of the Securities Act of 1933,
Sections 10(b), 20(a) and Rule 10b-5 of the Securities Exchange Act of
1934, negligent misrepresentations, and common law fraud and deceit.
In addition to the above-referenced class actions, three derivative
stockholder actions have been filed in the Court of Chancery of the State
of Delaware. These cases have been consolidated under the style In Re
Columbia Gas Derivative Litigation. The complaints in these actions name
as defendants the Board of Directors and the Corporation (nominal). The
complaints generally allege that the members of the Board of Directors
breached their fiduciary duties to the Corporation by failing to make
required disclosures thereby causing the Corporation to be subjected to
federal securities law liabilities.
II. Bankruptcy Matters
A. Matters in the United States Bankruptcy Court for the District of
Delaware
1. Columbia Gas Transmission Corporation v. The Columbia Gas
System, Inc. and Columbia Natural Resources, Inc., C.A. No. 92-35. (U.S.
Bankruptcy Ct. Dist. of Delaware, filed March 18, 1992). The Official
Committee of Unsecured Creditors of Columbia Transmission filed a complaint
(the Intercompany Complaint) challenging the status of approximately $1.7
billion of debt owed by Columbia Transmission to the Corporation and the
transfer of natural resource properties representing 450 billion cubic feet
of natural gas reserves and one million barrels of oil reserves to Columbia
Natural Resources, Inc. (Columbia Natural Resources) as well as other
intercompany transactions.
On May 14, 1992, the Official Committee of Unsecured Creditors
of Columbia Transmission filed a motion to withdraw the jurisdictional
reference to the U.S. District Court for the District of Delaware and filed
a demand for a jury trial. On February 9, 1993, the motion was denied by
the U. S. District Court and on August 20, 1993, the Third Circuit denied
the appeal by the Official Committee of Unsecured Creditors of Columbia
Transmission of the District Court's order allowing resolution of the
Intercompany Complaint before the Bankruptcy Court.
On June 11, 1992 the Corporation filed a motion and supporting
brief for partial dismissal or, in the alternative partial summary judgment
with respect to certain counts of the complaint which was supported by
Columbia's Equity Security Holders Committee and Unsecured Creditors
Committee. The motion has been fully briefed and a pretrial schedule has
been established which, if followed, would result in a trial of the
Intercompany
8
9
ITEM 3. LEGAL PROCEEDINGS (Continued)
Complaint in the spring of 1994. There has been no indication as to when
the Bankruptcy Court might act on Columbia's motion for summary judgment.
2. Motion to Fix Procedures to Establish Columbia Transmission's
Liability to Third Party Beneficiary Investor Complaints. On February 17,
1993, movants, who are investors in production companies and claim to be
third party beneficiaries of the contracts between Columbia Transmission
and the production companies, filed a motion seeking to have their status
as third party beneficiaries recognized and seeking to have their claims
against Columbia Transmission liquidated separate from the Estimation
Procedure established to deal with producer claims. By order dated April
5, 1993, the Bankruptcy Court lifted the stay in order to allow the New
Jersey State Court to determine whether plaintiffs enjoyed third party
beneficiary status in the pending State Court action. However, the
Bankruptcy Court with movants' acquiescence, held that movants' claim (to
the extent that they are established) would be governed by the estimation
procedure.
3. Bank of Boston, Trustee v. The Columbia Gas System, Inc. On
March 2, 1993, the Trustee for the Indenture under which debentures were
issued by the Employees Thrift Plan of Columbia Gas System (Plan) filed a
complaint against the Corporation alleging tortious interference with
contract and breach of duty. The Indenture Trustee alleges that the
Corporation is not acting in accordance with the Plan when it directs the
Plan Trustee to use sums paid by participating employers to match employee
contributions and not to pay debt service on the outstanding debentures.
The Corporation's Answer to the complaint alleging tortious interference
with contract for failure to pay installments due LESOP debenture holders
was filed April 2, 1993. On May 14, 1993, the Corporation filed a motion
for summary judgment challenging the Bank's standing to bring the action.
Bank of Boston filed its brief in opposition to the Corporation's motion
on June 14, 1993 and the Corporation's reply brief was filed on June 29,
1993. Bank of Boston filed an amended adversary complaint on June 30,
1993.
B. Appeals to the United States Court of Appeals for the Third Circuit
1. Enterprise Energy Corporation, et al., v. United States of
America, on behalf of its Internal Revenue Service On June 18, 1991, the
U.S. District Court for the Southern District of Ohio approved a settlement
of this class action suit by Appalachian oil and gas producers. The
settlement required Columbia Transmission to make two $15 million payments
into escrow, for distribution to class members as formal contract
amendments were finalized. The first $15 million was paid into escrow in
March 1991.
Columbia Transmission filed an application with the Bankruptcy
Court which would permit it to honor the settlement (including authority to
make the second $15 million payment into escrow in March 1992) but to
reject the amended contracts. On December 12, 1991, the Bankruptcy Court
ruled that distribution from escrow of the first $15 million payment could
be effected pursuant to the settlement; however, the Bankruptcy Court
denied Columbia Transmission's request for approval to make the second $15
million payment scheduled to be made in March 1992. Further, the
Bankruptcy Court granted the motion to reject the contracts, as amended,
pursuant to the Enterprise settlement.
On October 6, 1992, the District Court affirmed the Bankruptcy
Court's order denying Columbia Transmission's motion to assume the
executory settlement contract. Enterprise Energy Corp.'s request for
rehearing, reargument and reconsideration of the order denying Columbia
Transmission's motion to assume the executory settlement contract was
denied on April 27, 1993. On May 25, 1993, Enterprise Energy filed a
notice of appeal to the United States Court of Appeals for the Third
Circuit from the Bankruptcy Court order denying Columbia Transmission's
motion to require assumption or rejection of the executory settlement
contract. Briefing is complete. Oral argument was held January 18, 1993.
2. In re The Columbia Gas System, Inc. et al.; West Virginia
State Department of Taxation v. U.S., Nos. 93-7531 and 93-7532. This is
the appeal of the District Court's Memorandum Opinion and Order affirming
9
10
ITEM 3. LEGAL PROCEEDINGS (Continued)
the Bankruptcy Court's ruling that the property taxes centrally assessed by
West Virginia as public service business taxes for the "1992 tax year" were
incurred by Columbia Transmission prepetition and denying Columbia
Transmission's motion for authorization to pay the taxes. Briefing has
been completed and oral argument was heard on March 2, 1994.
3. The Columbia Gas System, Inc. and Columbia Gas Transmission v.
U.S. Trustee, No. 93-7609. On August 30, 1993, the Corporation and
Columbia Transmission filed an Appeal of the District Court's order
adopting the Magistrate's Report and Recommendation and granting the U.S.
Trustee's appeal of the Bankruptcy Court's July 31, 1993 order approving
certain investment guidelines and the Bankruptcy Court's order denying the
U.S. Trustee's Motion for Reconsideration of the Bankruptcy Court's July
31, 1993 order. On February 10, 1994, the District Court granted a stay
pending appeal of the August 19, 1993 order which approved the Magistrate's
Report and Recommendation.
III. Purchase and Production Matters (Unless otherwise noted, all matters
are stayed pursuant to Section 362 of the Bankruptcy Code)
A. Appalachian Producer Litigation
1. Enterprise Energy Corp. et al. v. Columbia Gas Transmission
Corp., C. A. No. C2-85-1209, (U. S. Dist. Ct., S. D. Ohio, filed July 26,
1985). See II B. 1.
2. Phillips Production Co. v. Columbia Gas Transmission Corp.,
C.A. No. 89-0269, (U.S. Dist. Ct., W.D. Pa. filed February 7, 1989). The
complaint as filed contained six separate counts involving ten gas purchase
contracts with Columbia Transmission. Plaintiff's principal claims were
for additional take-or-pay payments, for retroactive tight sands gas
pricing, and a challenge to Columbia Transmission's invocation of cost
recovery clauses in the gas purchase contracts. All claims except those
relating to Columbia Transmission's invocation of the cost recovery clause
were settled and dismissed December 18, 1989, pursuant to agreement of the
parties. The cost recovery claim was stayed pending resolution of
Enterprise Energy suit (discussed above). Thereafter, Phillips cost
recovery claim was stayed by Columbia Transmission's filing.
3. Columbia Gas Transmission Corp. v. Alamco, Inc. et al., C.A.
No. 88-C-38-2 (Harrison (W.Va) Cir. Ct. filed January 15, 1988). Under a
1983 release agreement, Columbia Transmission filed suit against Alamco,
Inc. (Alamco) contending that Alamco was obligated to sell gas to Columbia
Transmission at prices and under terms and conditions being generally
offered by Columbia Transmission at the time purchases were resumed as
opposed to the conditions of the original contract. Trial of the state
court action was interrupted and stayed by Columbia Transmission's petition
in Bankruptcy filed July 31, 1991. A parallel suit was filed by Alamco,
naming the Corporation, Columbia Transmission, Columbia Gas System Service
Corporation and Commonwealth Gas Pipeline Corporation, alleging antitrust
violations. In the opinion of counsel, the antitrust claim was barred by
the statute of limitations; however on March 13, 1991, Columbia
Transmission's and Commonwealth Gas Pipeline's motions to dismiss were
denied without prejudice to Columbia Transmission's right to assert, by
summary judgment or otherwise, that Alamco's claims are time barred, or
that Alamco cannot prove the allegations in its complaint.
In late May 1992, a settlement agreement in principle was
reached which was approved by the Bankruptcy Court on July 28, 1992. As a
result, after the order becomes final, these actions will be dismissed upon
the earlier of confirmation of a Columbia Transmission plan of
reorganization or closing of the Columbia Transmission bankruptcy
proceeding.
B. Southwest Producer Litigation (Suits naming Columbia Transmission
are stayed as to Columbia Transmission; indemnification agreements will be
effective if the contract providing indemnification is not rejected)
10
11
ITEM 3. LEGAL PROCEEDINGS (Continued)
1. Royalty Owners Litigation: The agreements between Columbia
Transmission and certain southwest producers effective in 1985 which
reformed gas purchase contracts have resulted in a number of lawsuits
against the producers. Under the agreements, Columbia Transmission has a
qualified obligation to indemnify the producers in certain instances
against claims by their royalty owners.
Certain suits were pending against Amoco Production Company for
which it was seeking indemnification from Columbia Transmission as of the
commencement of Columbia Transmission's proceeding in bankruptcy. In
November 1993, Columbia Transmission and Amoco entered an agreement,
subject to Bankruptcy Court approval, terminating the contracts and
providing that Amoco shall have an allowed unsecured claim for $4.1 million
for all royalty indemnification and excess royalty claims.
New Ulm and Fox v. Mobil Oil Corporation, Columbia Gas
Transmission Corp. and Columbia Gulf Transmission Co., C.A. No. 88-V-655
(155th Judicial Dist. Ct. of Austin County, TX). New Ulm alleged Columbia
Transmission incorrectly paid for gas on the basis of Columbia
Transmission's market-out price rather than the higher price New Ulm
claimed was available to it under the contracts.
After the Bankruptcy Court entered an order modifying the
automatic stay provisions of the Bankruptcy Code, jury trial began on June
22, 1992, and concluded with a verdict against Columbia Transmission on
July 2, 1992, in the amount of approximately $5.6 million, including
interest. On July 30, 1992, the Court denied Columbia Transmission's
motion for judgment notwithstanding the jury's verdict and entered judgment
against Columbia Transmission in such amount for actual damages,
prejudgment interest and attorneys' fees. Columbia Transmission's motion
for new trial was denied on October 12, 1992. Columbia Transmission has
perfected an appeal to the First Court of Appeals at Houston, Texas.
Briefing is complete and oral argument was held on December 7, 1993.
2. Wagner & Brown v. Columbia Gas Transmission Corp., C.A. No.
83-15091 (Orleans Parish (La.) Civ. Dist. Ct.). This suit involves
Columbia Transmission's alleged breach of a gas purchase and sales
agreement. The claims of Wagner & Brown have been settled, and the case
was dismissed as to Wagner & Brown on March 6, 1986. The claims of El Paso
Exploration Co. (now Meridian Oil Production, Inc. (Meridian)), which
intervened as a plaintiff and asserted all the claims and allegations made
by Wagner & Brown, including take-or-pay, price differential and specific
performance, have not been settled. In September 1990, Meridian served a
Second Amended Petition in which it alleges damages in excess of $60
million (and an additional $40 million of interest) as a result of Columbia
Transmission's failure to meet its take-or-pay and minimum take
obligations. The issue of price differential has been settled. A status
conference was held May 28, 1991, and a hearing on the plaintiff's motion
for partial summary judgment on Columbia Transmission's legal defenses was
held June 14, 1991.
A motion by Meridian for a Bankruptcy Court order lifting the
automatic stay so as to permit it to prosecute its claims against Columbia
Transmission was denied.
3. Koch Industries Inc. v. Columbia Gas Transmission Corp. C.A.
No. 89-2156 (U.S. Dist. Ct., E.D. La., filed May 12, 1989). On January 11,
1991, Columbia Transmission filed an action, Columbia Gas Transmission
Corp. v. Koch Industries. Inc., C.A. No. 91-0174, (U.S. Dist. Ct., E.D.
La). This lawsuit was related to the settlement of an earlier lawsuit
between the parties. Columbia Transmission sought an order declaring that
it is under no obligation to increase its purchase nominations under the
contracts because of Koch's unasserted right to correct imbalances between
it and other working interests owners in the acreage dedicated under the
contract. Koch filed a complaint seeking a contrary determination. Koch
Industries, Inc. v. Columbia Gas Transmission Corp., C.A. No. 91-0177
(U.S. Dist. Ct. E.D. La). The two cases were consolidated. Judgment in
favor of Koch Industries, Inc. and against Columbia Transmission was issued
on April 29, 1991. Columbia Transmission's motion to alter or amend the
judgment was denied on June 5, 1991. On June 19, 1991, Columbia
Transmission filed a Notice of Appeal to the Fifth Circuit. On August 20,
1991, the Clerk of the Court advised
11
12
ITEM 3. LEGAL PROCEEDINGS (Continued)
Columbia Transmission that the case was stayed during the Chapter 11
Bankruptcy proceedings.
4. Energy Development Corp. v. Columbia Gas Transmission Corp.,
C.A. No. CV91-0960, (U.S. Dist. Ct., W. D., La., division
Lafayette/Opelousas, filed May 13, 1991). Energy Development Corporation
alleges that Columbia Transmission breached the take-or-pay, minimum daily
quantity and inequitable withdrawal provisions of the gas purchase contract
between Energy Development Corporation and Columbia Transmission.
IV. Corporate Matters
1. The East Lynn Condemnation - United States v. 16.286.08 Acres
et al., C.A. No. 77-3324H (U. S. Dist. Ct., S.D. W.Va. filed December 26,
1976). The United States Corps of Engineers condemned certain fee lands in
Wayne County, West Virginia. On December 7, 1990, a United States District
Judge issued an order which adjudicates the amount of just compensation
Columbia Natural Resources was entitled to receive for the minerals taken,
including interest on the award through October 31, 1990, at $44,830,148.
In October 1991, checks totalling $52,254,883 were issued to Columbia
Transmission (holder of letter to the property when the condemnation
proceeding commenced), Columbia Natural Resources (current owner) and the
attorneys in the condemnation proceeding. To allow immediate deposit, the
checks were endorsed to Columbia Transmission. Columbia Natural Resources
and Columbia Transmission believe that a constructive trust in favor of
Columbia Natural Resources, the real party in interest, was created;
however, this view may be subject to challenge in Columbia Transmission's
bankruptcy proceeding.
V. Regulatory Matters
A. Take-or-Pay and Contract Reformation Costs Billed by Pipeline
Suppliers
1. Columbia Gas Transmission Corp., FERC Dkt. No. RP91-41, appeals
pending sub nom., Baltimore Gas & Electric Co. v. FERC, C.A. No. 88-1779
U.S. Ct. of App., D.C. Cir.) On February 3, 1992, FERC denied requests for
rehearing of orders accepting Columbia Transmission's Order No. 528
flowthrough filings, except to the extent that customers may challenge
Columbia Transmission's prudence for actions after April 1, 1987, to the
extent that it contributed to these upstream pipeline charges. On March
19, 1993 the FERC issued an order denying requests for rehearing and
permitting Columbia Transmission to flow through upstream pipeline Order
No. 528 costs. On December 30, 1993, the FERC issued an order denying
Cincinnati Gas & Electric Company's request for rehearing of the March 19,
1993 order, reaffirmed the February 3, 1992 and March 19, 1993 orders in
all respects, and indicated that no further rehearing requests would be
entertained. The Court issued a procedural order in the joint appeals,
leading to oral argument on May 10, 1994.
2. AGD v. FERC, No. 88-1385 (U.S. Ct. of App., D.C. Cir.). On
December 28, 1989, the U.S. Court of Appeals for the District of Columbia
Circuit ruled that the deficiency-based direct billing of Order No. 500
costs approved by the FERC in Tennessee Gas Pipeline Co., No. RP86-119, is
unlawful retroactive ratemaking and violates the filed rate doctrine. On
October 9, 1990, the U.S. Supreme Court denied certiorari in AGD.
Accordingly, the FERC issued its order on remand on November 1, 1990 (Order
No. 528).
The FERC has approved Order No. 528 settlements for some of
Columbia Transmission's pipeline suppliers. However, there are remaining
unresolved direct upstream pipeline supplier Order No. 528 proceedings.
The Order No. 528 filings and settlements to date have reduced
Columbia Transmission's Order No. 528 liability to upstream pipelines
significantly. Columbia Transmission's customers continue to challenge its
right to recover any of these amounts.
B. Direct Billing of Past Period Production and Production-Related
Costs
12
13
ITEM 3. LEGAL PROCEEDINGS (Continued)
1. Columbia Gas Transmission Corp. v. FERC., C.A. No. 88-1701
(U.S. Ct. of App., D.C. Circuit). On February 9, 1990, the Court issued
its opinion finding that the FERC's orders authorizing five of Columbia
Transmission's upstream pipeline suppliers to directly bill past period
production related costs (Order Nos. 94 and 473) to customers allocated
based upon past period purchases violates the filed rate doctrine and the
rule against retroactive ratemaking. Therefore, the Court struck the
orders authorizing direct billing and remanded the issue to the FERC for
further proceedings. On October 9, 1990, the U.S. Supreme Court denied
certiorari.
Columbia Transmission reached settlements with Panhandle,
Trunkline, Texas Eastern and Texas Gas, which provided for full
refunds of Order No. 94 direct billings with rebillings to Columbia
Transmission of lesser amounts. These settlements would reduce Columbia
Transmission's Order No. 94 direct billing liability to these pipelines
from $29 million to $17 million exclusive of interest. Columbia
Transmission's customers have objected to those settlements because they
contemplate Columbia Transmission's recovery of these rebilled amounts
from its customers. On February 10, 1993, the FERC approved Columbia
Transmission's Order 94 settlement with four pipeline suppliers, which
settlements authorized Columbia Transmission to recover the rebilled
payments to its' customers.
On October 28, 1993, Transco and Columbia Transmission filed a
letter with the FERC indicating that the remaining issues have been
resolved, and that they agreed on a refund to Columbia Transmission of $1.4
million. The FERC is treating this as a settlement offer.
On January 12, 1994, the FERC issued an order on rehearing in
which it reversed its earlier conclusions and rejected the Order No. 94
settlements with Panhandle, Trunkline, Texas Eastern and Texas Gas. FERC
now holds that Columbia Transmission's 1985 PGA settlement essentially bars
recovery of any of the rejected costs. The January 12, 1994, order
required Panhandle, Texas Eastern and Texas Gas to refund all Order No. 94
costs, but absolved them of responsibility for paying interest. On
February 14, 1994, Columbia Transmission and the upstream pipelines
requested rehearing of the January 12 orders. The pipelines have received
an extension of time to make refunds until after the FERC rules on
rehearing. Columbia Transmission has asked the FERC to hold the Transco
settlement in abeyance until after the FERC rules on rehearing. Transco
has opposed this request.
C. WACOG Recovery.
1. Columbia Gas Transmission Corp., FERC Dkt. No. RP91-206. On
August 1, 1991, Columbia Transmission filed for a 12- month, 20 cent
surcharge to its commodity rate to recover certain pre-April 1, 1985,
supplier costs which it is entitled to recover, in accordance with the
terms of its 1985 Purchased Gas Adjustment settlement, to the extent that
its annual weighted average cost of gas (WACOG) compares favorably with the
WACOGs of competing pipelines. On August 30, 1991, FERC rejected such
filing, without prejudice, finding that Columbia Transmission's calculation
of its WACOG was inconsistent with the 1985 settlement. On May 22, 1992,
the FERC denied Columbia Transmission's request for rehearing. Columbia
Transmission has filed a petition for review of these orders. The matter
has been briefed by the parties and oral argument was held on October 22,
1993. On January 3, 1994, Columbia Transmission filed an offer of
settlement in Docket Nos. RP93-161 and RP94-1 (see C.3. below) which
provides that, upon final approval of the settlement, Columbia Transmission
will dismiss its appeal.
2. Columbia Gas Transmission Corp., FERC Dkt. No. RP92-215. On
July 31, 1992, Columbia Transmission proposed an 8 cents per Dekatherm
surcharge for the 12 months commencing September 1, 1992. On August 31,
1992, the FERC accepted Columbia Transmission's filing subject to
suspension, refund and a technical conference. After such technical
conference and statements of position by the parties, the FERC rejected the
WACOG filing on January 21, 1993 and ordered Columbia Transmission to
refund all WACOG charges which it previously collected. On November 26,
1993, the FERC denied Columbia Transmission's request for rehearing of the
January 21, 1993, order. Columbia Transmission has filed a petition for
review of these orders with the
13
14
ITEM 3. LEGAL PROCEEDINGS (Continued)
United States Court of Appeals for the D.C. Circuit. On January 3, 1994,
Columbia filed an offer of settlement in Docket Nos. RP93-161 and RP94-1
(see C.3. below) which provides that, upon final approval of the
settlement, Columbia Transmission will dismiss its appeal of the orders.
3. Columbia Gas Transmission Corp., Dkt. Nos. RP93-161 and RP94-1.
These filings proposed a WACOG surcharge for the 1993-94 period, the last
year Columbia Transmission is eligible to file such surcharge. The filing
in RP93-161 proposed to collect a 28 cents per Dth surcharge for sales
customers for the months of September and October 1993. The filing in
RP94-1 proposed to collect a surcharge of 7.22 cents per Dth for most firm
transportation customers from November 1, 1993 when Columbia Transmission
implemented Order 636, through October 31, 1994. On January 3, 1994,
Columbia Transmission filed a settlement which is unopposed to obtain all
WACOG surcharges collected during September-December, 1993 and collect a
WACOG surcharge of 3.8c. per Dth during January-October, 1994. If Columbia
Transmission's WACOG surcharge revenues exceed $42.8 million, it will
refund 90% of the excess to customers and retain the remaining 10%. FERC
approved the settlement on February 28, 1994.
VI. Other
A. Canada Southern Petroleum Ltd. v. Columbia Gas Development of
Canada Ltd. et al., (C.A. No. 9001-03466, Court of Queen's Bench, Alberta,
Canada, filed March 7, 1990). The plaintiff asserts, among other things,
that the defendant working interest owners, including Columbia Gas
Development of Canada Ltd. (Columbia Canada) and various Amoco affiliates,
breached an alleged fiduciary duty to ensure the earliest feasible
marketing of gas from the Kotaneelee field (Yukon Territory, Canada). The
plaintiff seeks, among other remedies, the return of the defendants'
interests in the Kotaneelee field to the plaintiff, a declaration that such
interests are held in trust for the plaintiff, and an order requiring the
defendants to promptly market Kotaneelee gas or assessing damages.
The judge granted the application of Allied Signal, Inc., Home
Oil Company and Kern County Land Company to relieve them of the requirement
to participate in the proceedings. An appeal of the order by Amoco is
pending.
Examination for discovery is still proceeding in the referenced
actions. Columbia Canada has had a second round of discovery of its
witnesses and has made undertakings to provide additional information which
it is in the process of preparing. Amoco has not yet fulfilled the
undertakings from its first round of discoveries. Upon it doing so, it is
reasonable to suppose that further discoveries of Amoco will be required by
Canada Southern.
None of the defendants has yet conducted any discovery of
Canada Southern nor of one another. On the present schedule, it is likely
that this discovery process will continue well into 1994.
In early 1993, Canada Southern filed a motion to amend their
statement of claim to seek an accounting of the amount of operation costs
properly recoverable by the working interest holders including Columbia
Canada. Columbia has not consented to the amendment and contends that any
amounts accrued since the initial statement of claim in 1988 should be
barred and more basically, that litigation is inappropriate prior to an
audit.
Note: Columbia Canada was sold to Anderson Exploration Ltd.
effective December 31, 1991, and the company name subsequently changed to
Anderson Oil & Gas, Inc. Pursuant to an Indemnification Agreement re
Kotaneelee Litigation, Columbia agreed to indemnify and hold Anderson
harmless from losses due to this litigation. An escrow account in the
amount of approximately $30,000,000 (Cdn) was established as partial
security for the indemnification obligation. Upon emerging from
bankruptcy, an additional deposit to the Escrow Account of $25,000,000
(Cdn) will be required in cash or by letter of credit.
14
15
ITEM 3. LEGAL PROCEEDINGS (Continued)
B. Minerals Management Service (MMS) has demanded that Columbia
Gas Development Corporation (Columbia Development) pay additional royalties
for the period October 1, 1983 to December 31, 1985, claiming the prices
received by Columbia Development from its affiliate under non-arm's-length
contracts were less than the prices received for like-quality gas under
comparable arms-length contracts in the field. A complaint was filed by
Columbia Development in U.S. District Court in Dallas on October 23, 1992,
(Case No. 3:92-CV2199-T), claiming that the six-year statute of limitation
applicable to the claim has expired and a protective administrative appeal
was filed with the MMS on October 27, 1992. A decision was rendered August
27, 1993, by the Northern District of Texas District Court in favor of the
government on the statute of limitations issue, reasoning that the MMS
order to pay is not "an action for money damages" under the language of the
statute and further granted the government's motion to dismiss in part on
the basis of the doctrine of exhaustion of administrative remedies.
Columbia Development has appealed the District Court decision to the Fifth
Circuit Court of Appeals. Columbia Development's initial brief was filed
on January 10, 1994. In another case, the 10th Circuit Court of Appeals
ruled in favor of the government on the statue of limitations issue on the
grounds that the six-year statute of limitations is tolled until such time
as the government could reasonably have known about all facts material to
its right of action.
In addition, the MMS audited Columbia Development for the
period January 1, 1986, through December 31, 1990, and has made a similar
but unquantified claim. Columbia Development has appealed this claim to
the Interior Board of Land Appeals and has obtained the MMS's pricing data
and analyzed it using comparable pricing from surrounding OCS blocks to
determine probable liability. Meetings with the MMS to eliminate less
controversial claims (third party sales and sales at MLP) and to present
the comparable pricing analysis have been held. MMS is reviewing the
information presented.
VII. Environmental
A. Commonwealth of Kentucky Natural Resources and Environmental
Protection Cabinet, Department for Environmental Protection. On January
22, 1992, Columbia Transmission received Notices of Violation (NOV) from
the Commonwealth of Kentucky, Natural Resources and Environmental Cabinet,
Department of Environmental Protection (KyDEP) with respect to ten
compressor station sites in the Commonwealth of Kentucky. These notices
generally cite the release or disposal of waste materials or hazardous
substances, including but not limited to polychlorinated-biphenyls (PCBs).
It appears from a letter dated January 13, 1992, from the Natural Resources
Environmental Protection Cabinet, Department of Law, that the violations
have been asserted for the purposes of establishing the Cabinet's
prepetition claims against Columbia Transmission.
The alleged violations provide for fines and penalties that
apply separately for each violation and each day of noncompliance which, in
the aggregate, are significant. Columbia Transmission's prior experiences,
however, as well as those of other companies in the industry, have
demonstrated that such fines and penalties have not been assessed at the
maximum rate when the company is cooperating with governmental agencies and
authorities in remediation activities. Columbia Transmission intends to
continue to work with the KyDEP in negotiating a consent decree approving
prior remediation activity and a prospective remediation plan.
B. In the Matter of Columbia Gas Transmission Corp., (Region
III). Columbia Transmission was subpoenaed to supply information under the
authority of the Toxic Substance Control Act (TSCA), the Resource
Conservation Recovery Act and the Comprehensive Environmental Response
Compensation and Liability Act of 1980. Documents were accumulated and
delivered in June and July and conferences with personnel of the
Environmental Protection Agency Region III have been held. Columbia
Transmission is continuing to provide documents and information to
Environmental Protection Agency Region III and has begun negotiation of a
possible consent decree under the TSCA approving prior remediation activity
and prospective remediation plans developed by Columbia Transmission.
Fines or penalties may also be included.
15
16
ITEM 3. LEGAL PROCEEDINGS (Continued)
C. Portsmouth Redevelopment and Housing Authority and
Commonwealth Gas Services, Inc. (Commonwealth) v. BMI Apartment Associates,
C.A. No. 2:93CV242, (U.S. Dist. Ct. E.D. Va., filed March 25, 1993.) A gas
manufacturing plant had been operated in Portsmouth, Virginia by Portsmouth
Gas Co on a site that was subsequently sold by Portsmouth Gas Co. to the
Portsmouth Redevelopment and Housing Authority, which removed equipment and
sold the property to developers of apartment complexes and single-family
homes. Portsmouth Gas Co. was later acquired by Commonwealth. On February
10, 1993, without admitting or conceding responsibility for the site,
Commonwealth provided notice of site contamination to the United States
Environmental Protection Agency. On March 25, 1993, Commonwealth and the
Portsmouth Housing and Redevelopment Authority filed a cost recovery action
in federal court under the Comprehensive Environmental Response
Compensation and Liability Act of 1980 against the current and past owners
of a former manufactured gas plant site and sought a court order to obtain
access to the site for health risk testing. BMI Apartment Associates
(BMI), the owners of apartments on the site objected to the request for
access and filed a "citizens' suit" under the Resource Conservation and
Recovery Act as a counterclaim and cross-claim. On June 14, 1993, the
United States District Court granted Commonwealth and the Portsmouth
Redevelopment and Housing Authority access to the site to perform the
health risk testing and testing on-site was completed June 24, 1993. On
July 28, 1993, the Court dismissed the counterclaims of BMI that were drawn
on RCRA and loss of contribution protection under CERCLA. The remaining
liabilities, damages and allocations are similar for both defendants and
plaintiffs. The Health Risk Assessment Report was provided to all parties
on August 27, 1993. It finds "no imminent risk to public health." Further
investigation will be conducted without relocating residents. In
mid-September, 1993, the judge granted an eight month stay of all legal
proceedings to permit Commonwealth to conduct full site investigation and
provide the opportunity for the parties to discuss settlement. The
workplan was completed and work began on November 1, 1993. Emergency
permits for waste handling from the City of Portsmouth were obtained to
facilitate the investigation. Residents and nearby homeowners were
notified of the work. Commonwealth met with the voluntary Remediation
Group of VaDEQ. A draft consent agreement delineating the VaDEQ's
supervisory responsibility for site work is being developed. On February
14, 1994, a Magistrate was appointed to facilitate settlement discussions.
D. Commonwealth Gas Services/Virginia Department of
Environmental Quality. On February 9, 1993, Commonwealth reported to the
Virginia Department of Environmental Quality's (VaDEQ) State Water Control
Board that an oily substance was seeping through a retaining wall at a
former manufactured gas plant site at Petersburg, Virginia. On April 5,
1993 Commonwealth received a request from the State Water Control Board to
investigate the seep and submit a report to the Board. Commonwealth has
retained a consultant to investigate the seep and prepare the report. Site
assessment was submitted to the VaDEQ on July 20, 1993. That report
recommends removal of contents of a tank behind the retaining wall. The
report also disclosed an additional seep of materials from the creek
upstream of the retaining wall area. On July 27, 1993, VaDEQ accepted
Commonwealth's recommendations on the two seeps. Commonwealth is
proceeding to implement those recommendations over the next six months. On
November 1, 1993, a report on the creek bank seep was sent to VaDEQ. It
notes fairly widespread groundwater and soil contamination, as well as
identifying the source of the creek bank seep. On December 10, 1993,
Commonwealth met with the VaDEQ regarding the recently filed report.
Commonwealth consultants are developing a workplan to address the
contamination noted in the report. Commonwealth is now dealing with VaDEQ
remediation group and is in the process of developing a draft memorandum of
understanding delineating the course of action to be taken.
E. In Re Columbia Gas Transmission (Region V). On January 28,
1994, Columbia Transmission received from USEPA Region V an Information
Request pursuant to the Resource Conservation and Recovery Act (RCRA). The
Agency requests Columbia Transmission to submit information and knowledge
relating to its generation and management of natural gas pipeline
condensate, used engine oil and similar liquids in the state of Ohio.
Transmission is in the process of analyzing the information requested and
will be discussing this Information Request with Region V.
16
17
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The common stock of the Corporation is traded on the New York Stock
Exchange under the ticker symbol CG and abbreviated as either ColumGas or
ColGs in trading reports. The number of shareholders of record on February
28, 1994, was approximately 64,271 and the stock closed at $28.375. On
June 19, 1991, the Corporation suspended the dividend on its common stock.
Management cannot determine at this time when dividends will again be paid.
See Item 7 on page 51 for additional information regarding the
Corporation's common stock prices and dividends.
17
18
ITEM 6. SELECTED FINANCIAL DATA
SELECTED FINANCIAL DATA
The Columbia Gas System, Inc. and Subsidiaries
($ in millions except per share amounts) 1993* 1992* 1991* 1990 1989
------------------------------------------------------------------- ------------ ------------- ----------------------------
INCOME STATEMENT DATA ($)
Total operating revenues 3,391.2 2,922.0 2,576.8 2,357.9 3,204.4
Products purchased 1,574.5 1,236.9 1,056.5 846.8 1,669.0
Earnings (Loss) on common stock
before extraordinary item and
accounting changes 152.2 90.9 (794.8) 104.7 145.8
Earnings (Loss) on common stock 152.2 51.2 (694.4) 104.7 145.8
----------------------------------------------------------------------------------------------------------------------------
PER SHARE DATA
Earnings (Loss) per common share ($):
Before extraordinary item and
accounting changes 3.01 1.79 (15.72) 2.21 3.21
Earnings (Loss) on common stock 3.01 1.01 (13.74) 2.21 3.21
Dividends:
Per share ($) - - 1.16 2.20 2.00
Payout ratio (%) N/M N/M N/M 99.5 62.3
Average common shares outstanding (000) 50,559 50,559 50,537 47,316 45,494
----------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA ($)
Capitalization excluding liabilities
subject to Chapter 11:
Common stock equity 1,227.3 1,075.1 1,006.9 1,757.8 1,620.3
Long-term debt 4.8 5.4 6.1 1,428.7 1,196.0
Short-term debt and current maturities** 1.3 1.4 138.9 770.7 681.4
Total 1,233.4 1,081.9 1,151.9 3,957.2 3,497.7
Total assets 6,957.9 6,505.9 6,332.2 6,196.3 5,878.4
----------------------------------------------------------------------------------------------------------------------------
OTHER FINANCIAL DATA
Capitalization ratio (%) (including short-term
debt and current maturities**):
Common stock equity 99.5 99.4 87.4 44.4 46.3
Debt 0.5 0.6 12.6 55.6 53.7
Capital expenditures ($) 361.3 299.7 381.9 629.6 473.5
Net cash from operations ($) 850.4 765.4 531.6 420.1 400.5
Book value per common share ($) 24.27 21.26 19.92 34.83 35.50
Return on average common equity
before extraordinary item (%) 13.2 8.7 N/M 6.2 9.2
----------------------------------------------------------------------------------------------------------------------------
N/M - Not meaningful
* Reference is made to Notes 1A and 2 of Notes to Consolidated
Financial Statements.
**Prior to its Chapter 11 filing, the Corporation made extensive
use of variable rate debt since the associated cost was normally
less than senior long-term debt. Inclusion of the short-term
debt in years prior to 1991 makes those historical ratios more
meaningful.
18
19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Index Page
Bankruptcy Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Oil and Gas Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Transmission Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Distribution Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
Other Energy Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
Consolidated Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
Liquidity and Capital Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51
BANKRUPTCY MATTERS
On July 31, 1991, The Columbia Gas System, Inc. (Corporation) and its
wholly-owned subsidiary, Columbia Gas Transmission Corporation (Columbia
Transmission), filed separate petitions seeking protection under Chapter 11
of the Federal Bankruptcy Code. Both the Corporation and Columbia
Transmission were granted debtor-in-possession status under the Bankruptcy
Code, allowing them to continue normal business operations subject to the
jurisdiction of the United States Bankruptcy Court for the District of
Delaware (Bankruptcy Court).
Columbia Transmission's Plan of Reorganization
The Corporation's and Columbia Transmission's discussions with the
Official Committee of Unsecured Creditors of Columbia Transmission
(Columbia Transmission Creditors' Committee) to negotiate a reorganization
plan for Columbia Transmission and expedite emergence from Chapter 11
proceedings had been largely unsuccessful. Therefore, on January 18,
1994, Columbia Transmission filed, with the Corporation as cosponsor, a
reorganization plan (plan) and a disclosure statement, for consideration
by its creditors and other interested parties. The plan, which management
believes is fair and equitable, proposes to pay 100 percent for all
priority, administrative and secured claims and offers various classes of
general unsecured creditors, including producers whose gas contracts were
rejected by Columbia Transmission, between 80 and 100 percent of Columbia
Transmission's estimates of their allowable claims. The $3.3 billion
total distribution proposed in Columbia Transmission's plan is based on an
estimated value for Columbia Transmission of $3.1 billion and includes
significant financial contributions by the Corporation. The plan is
premised on a proposed omnibus settlement whereby the Corporation would
settle the Intercompany Complaint and facilitate Columbia Transmission's
reorganization by (i) accepting the value of the Corporation's secured
claims against Columbia Transmission in the form of secured debt and
equity securities of Columbia Transmission, and (ii) ensuring the cash (or
at the option of the Corporation cash and $100 million market value of the
Corporation's common stock) necessary to bring the aggregate distribution
to $3.3 billion. Creditors, other than the Corporation, would share in
distributions of over $1.2 billion in cash. In addition, the Corporation
would consent to the reorganized Columbia Transmission's assumption of
responsibility for public environmental enforcement agency claims so that
the recoveries of the other creditors would not, with minor exceptions, be
diminished by the environmental liabilities of Columbia Transmission's
estate.
The plan provides that Columbia Transmission will remain a wholly-owned
subsidiary of the Corporation, will continue to offer an array of
competitive transportation and storage services, and will retain ownership
of its 18,800-mile pipeline network and related facilities.
Columbia Transmission's proposed business solution will offer to producers,
whose gas supply contracts were rejected or who have prepetition claims
under those contracts, individual, specific settlements of the producers'
claims that are based upon uniform assumptions and principles and which, in
the view of Columbia Transmission's management, are fair and reasonable
settlement values. These specific settlement proposals are being developed
19
20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
and will be filed as an adjunct to the plan. Columbia Transmission
estimates that aggregate distributions to producers under the plan would
come to approximately $900 million.
In general, the plan provides for immediate cash payment in full to all
priority claims, all secured claims held other than by the Corporation,
trust fund claims, administrative expenses and unsecured claims of $50,000
or less. The Corporation's secured claims will be satisfied in full with
new secured debt and equity securities to be issued by the reorganized
Columbia Transmission. Unsecured claims between $50,000 and $250,000 would
receive 95 percent of their allowed claims in cash. All other unsecured
claims, including the Corporation's unsecured debt and producer contract
rejection claims, would receive between 80 and 100 percent of their allowed
claims based on current projections. With respect to some of the classes
of creditors, the treatment described above depends on the acceptance of
the plan by the relevant class. At this time, no creditors have agreed to
any of the proposed plan's provisions, and the ultimate confirmed plan of
reorganization could be materially different from this initial filing.
Although Columbia Transmission's plan utilizes June 30, 1994, as an assumed
date of emergence from bankruptcy, the actual date of emergence will depend
on the time required to complete the bankruptcy process and obtain
necessary creditor, judicial and regulatory approvals. As part of its
filing with the Bankruptcy Court, Columbia Transmission requested that the
court defer scheduling required proceedings on the plan and related
disclosure statement in order to permit discussions of the plan, including
the settlements proposed therein, with Columbia Transmission's creditors,
official committees and other interested parties.
Under bankruptcy procedures, after Columbia Transmission's disclosure
statement has been approved by the Bankruptcy Court, the disclosure
statement and the reorganization plan will be sent to the company's
creditors for voting.
The Corporation intends to file a plan for its reorganization which will be
consistent with the financial aspects and structure of Columbia
Transmission's proposed plan of reorganization. Both plans will be subject
to a lengthy review and approval process, including SEC approval, and
obtaining adequate financing.
Implementation of Columbia Transmission's plan, and the levels and timing
of distributions to its creditors, are subject to a number of risk factors
which could materially impact their outcome. The plan sets forth numerous
conditions to its confirmation and consummation. The failure to satisfy
these conditions in accordance with the terms of the plan would have a
material adverse effect on the outcome of Columbia Transmission's
bankruptcy and on the Corporation. These conditions include, among others,
the confirmation of a reorganization plan for the Corporation, the receipt
of necessary approvals for the implementation of Columbia Transmission's
plan and the recovery of regulatory and tax benefits which are fundamental
to the plan's viability. Both companies anticipate emerging from
bankruptcy at the same time. The provisions of the reorganization plans of
either Columbia Transmission or the Corporation that are ultimately
implemented could be materially different from this initial filing for
Columbia Transmission and have a material adverse effect on the Corporation
and its subsidiaries and on the rights of shareholders and holders of debt
and other obligations.
Events Leading to Bankruptcy Filings
Columbia Transmission's Chapter 11 filing was precipitated by a combination
of events that adversely affected its physical operations and financial
viability. Most notable were federal legislative and regulatory actions,
instituted years after Columbia Transmission's gas purchase contracts were
signed, that significantly impacted Columbia Transmission's ability to sell
the gas it had contracted to buy and to recover its costs from its
customers. These problems were exacerbated by record-setting warm weather
in 1990 and 1991, which caused spot market prices for gas to plunge and
created excess transportation capacity, thus making an unexpected and
persistent oversupply of bargain-priced gas available to Columbia
Transmission's customers. As a result, Columbia Transmission's ability to
market its gas was severely undercut, substantially reducing both sales
volumes and revenues.
20
21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
After completing studies, in early June 1991, that revealed the magnitude
of Columbia Transmission's gas supply problems, the Corporation announced
on June 19, 1991, that: (i) it anticipated that a substantial portion of
Columbia Transmission's exposure on above-market priced gas purchase
contracts would be charged to income in the second quarter; (ii) Columbia
Transmission was launching a comprehensive effort to renegotiate or
terminate all of its above-market gas purchase contracts under a program
which contemplated offering producers up to $600 million of Columbia
Transmission's obligations as compensation for restructuring their
contracts; (iii) the Corporation was suspending the dividend on its common
stock; and (iv) corporate officers were meeting with bank lenders that day
seeking to reestablish the Corporation's credit facilities on revised terms
in view of Columbia Transmission's financial difficulties. In addition,
Columbia Transmission's financial problems were exacerbated when the West
Virginia Supreme Court ordered the posting of a $10 million bond by July
29, 1991, in order to stay the execution of a $29.5 million judgment in a
lease dispute which was subsequently reversed.
As of July 31, 1991, the Corporation was in default on $83.5 million of
short-term obligations and the negotiations with banks and producers had
met with only limited success. As a result, on July 31, 1991, the
Corporation and Columbia Transmission filed for protection under Chapter 11
of the Federal Bankruptcy Code in the Bankruptcy Court. A discussion of
the proceedings under Chapter 11 protection is included in Note 2 of Notes
to Consolidated Financial Statements.
In contrast to the situation of many other Chapter 11 debtors,
reorganization of Columbia Transmission has not been hampered by
unprofitable or marginal business operations. Rather, in Columbia
Transmission's case the achievement of the Chapter 11 objective of
reorganization has been impacted by the enormity and complexity of the
disputed and contingent claims filed against it by unaffiliated creditors
and by attempts on behalf of those creditors to obtain recoveries on such
claims from the assets of the Corporation's estate. In addition, Columbia
Transmission's status as a regulated gas transmission company under the
Natural Gas Act (NGA) and its resulting obligations has brought into the
bankruptcy forum creditors' rights issues which are complicated by public
law issues arising under the NGA.
Bankruptcy Issues
On March 19, 1992, the Columbia Transmission Creditors' Committee filed a
complaint (Intercompany Complaint) with the Bankruptcy Court alleging that
the $1.7 billion of Columbia Transmission's secured and unsecured debt
securities held by the Corporation should be recharacterized as capital
contributions (rather than loans) and equitably subordinated to the claims
of Columbia Transmission's other creditors. The Intercompany Complaint
also challenges interest and dividend payments made by Columbia
Transmission to the Corporation of approximately $500 million for the
period from 1988 to the petition date and the 1990 property transfer from
Columbia Transmission to Columbia Natural Resources, Inc. (CNR) as an
alleged fraudulent transfer. Based on the SEC's standardized measurement
procedures, CNR's properties had a reserve value of approximately $387
million as of December 31, 1993, a significant portion of which is
attributable to the transfer from Columbia Transmission. In May 1992,
Columbia Transmission Creditors' Committee filed with the U.S. District
Court a motion for a jury trial and to move the Intercompany Complaint from
the Bankruptcy Court to the U.S. District Court. This motion was denied
and subsequently appealed to the Third Circuit Court of Appeals (Third
Circuit). In June 1992, the Corporation filed a motion with the Bankruptcy
Court seeking dismissal of, or summary judgment on, principal portions of
the Intercompany Complaint. On August 20, 1993, the Third Circuit denied
Columbia Transmission Creditors' Committee's appeal, allowing the
Bankruptcy Court to consider the merits of the Intercompany Complaint and
act upon the Corporation's June 1992 motion for summary judgment. The
Bankruptcy Court has not acted on the Corporation's motion for summary
judgment, but tentatively scheduled a trial on the Intercompany Complaint
to begin June 13, 1994. Management believes that the Intercompany
Complaint is without merit; however, the ultimate outcome of these issues
is uncertain at this stage of the proceedings.
Discussions with Columbia Transmission's creditors in an attempt to
establish the value of the estate and to resolve
21
22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
the matters raised in the Intercompany Complaint are ongoing. Since the
standing and value of the Corporation's debt investment in Columbia
Transmission is crucial to the determination of the value of the
Corporation's estate, the Corporation's reorganization could be affected by
the ultimate outcome of the Intercompany Complaint.
At December 31, 1993, the Corporation's investment in Columbia Transmission
is as follows:
$ millions
------------
Secured Debt
First Mortgage Bonds 930.4
Gas Inventory Loan(s) 410.0
Accrued interest on secured debt 346.4
Unsecured Debt
Installment Notes 343.9
Accrued interest to petition date 7.1
Equity investment (517.2)
---------
Total Investment 1,520.6
=========
The Corporation has claims against Columbia Transmission's estate for money
it borrowed which are secured by substantially all of Columbia
Transmission's assets, including cash. This indebtedness bears interest at
rates significantly higher than those earned by Columbia Transmission on
its excess cash because of bankruptcy imposed limitations on Columbia
Transmission's temporary investments and the current level of interest
rates. As a result, the growth in Columbia Transmission's secured interest
obligations has exceeded its interest earnings on its cash available for
debt service by an amount projected to exceed $300 million by the end of
June 1994.
The Internal Revenue Service (IRS) filed identical claims of $553.7 million
against both debtor companies and the consolidated Columbia Gas System for
tax deficiencies, interest and penalties for the years 1983-1990.
Negotiations with IRS representatives have resulted in a settlement on all
of the issues included in the IRS claims. This settlement has been
documented in a written closing agreement and filed with the Joint
Committee on Taxation of the U.S. Congress for formal approval. The IRS
settlement also requires Bankruptcy Court approval. Recording the IRS
settlement reduced 1993 net income by $44.3 million.
Columbia Transmission has recorded liabilities of approximately $1.2
billion to reflect the estimated effects of its above- market producer
contracts and estimated supplier obligations associated with pricing
disputes and take-or-pay obligations for historical periods. With
Bankruptcy Court approval, Columbia Transmission rejected more than 4,800
above-market gas purchase contracts with producers. The producers whose
gas purchase contracts were rejected filed claims for damages that, after
being adjusted for duplicative and other erroneous claims, are in excess of
$13 billion. The Bankruptcy Court approved the appointment of a claims
mediator in 1992 to implement a claims estimation procedure related to the
rejected above-market producer contracts and other producer claims. The
mediator held hearings on generic issues and various estimation
methodologies and discovery matters during 1993. Columbia Transmission
anticipates that the mediator may issue recommended determinations during
the second quarter of 1994 which, under the Bankruptcy Court-approved
estimation procedure, are expected to provide the basis for a recalculation
of producer contract rejection claims. In Columbia Transmission's
judgment, the positions taken by all producers before the claims mediator
and the evidence presented demonstrate that the total level of allowable
contract rejection claims, generically determined, will not exceed 1/10th
of the $13 billion asserted in the claims as filed and is likely to be
between $600 million and $950 million. The acceptance of certain positions
advanced by Columbia Transmission on the evidence of record, as well as
Columbia Transmission's as yet unheard defenses, could decrease
substantially this range of possible aggregate outcomes. Resolution of the
contract-specific issues
22
23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
not yet presented could increase or decrease individual claims materially
but should not significantly alter the range of possible aggregate
outcomes.
The resolution of these issues can significantly influence future reported
financial results. Accounting standards require that as claim amounts are
allowed by the Bankruptcy Court, the full amount of the allowed claim must
be recorded. This could result in liabilities being recorded which bear
little relationship to the amounts ultimately required to be paid in
settlement of those claims and could conceivably exceed the Corporation's
total investment in Columbia Transmission. Any such distortion would not
be corrected until final plans of reorganization are approved for the
Corporation and Columbia Transmission.
At a hearing on February 23, 1994, the Bankruptcy Court granted the
Columbia Transmission Creditors' Committee's motion for the establishment
of a data room that will make business information on Columbia Transmission
available to third parties who may be interested in the company. In
granting the motion, the Bankruptcy Court instructed the parties to jointly
develop proposed data room procedures which should provide for a
substantial entrance fee, exclude Columbia Transmission's future business
plans and projections and establish strong confidentiality protections.
The Bankruptcy Court also instructed that such procedures should be filed
with the Bankruptcy Court by March 11, 1994, for a hearing on March 15,
1994. Columbia Transmission is working toward the expeditious development
and conclusion of the data room process in order to minimize any potential
delays to its reorganization efforts. The Corporation has stated that its
Columbia Transmission subsidiary is not for sale but that if a credible,
bona fide third party offer is made for that company, it would be given
appropriate consideration.
Other Related Issues
Corporation's Objection to Claims
In 1993, the Bankruptcy Court granted the Corporation's request to expunge
over 7,100 proofs of claim filed against the Corporation. As a result,
less than 500 filed claims against the Corporation currently remain to be
resolved.
Leveraged Employee Stock Ownership Plan
On May 31, 1992, the debt service payment on debentures issued under the
Leveraged Employee Stock Ownership Plan (LESOP) portion of the Columbia's
Employees' Thrift Plan (Thrift Plan) was not made and no further debt
service payments are likely to be made until the Corporation emerges from
bankruptcy. Under the terms of the Corporation's guarantee of the
debentures, the LESOP debenture holders will become creditors of the
Corporation, subordinated to holders of the debentures and medium-term
notes issued by the Corporation. Management has concluded that it is more
equitable and may be economically preferable to pay all creditors at the
same time in accordance with consummation of the Corporation's plan of
reorganization.
The Trustee for the Indenture under which the debentures were issued by the
Thrift Plan filed a complaint against the Corporation on March 2, 1993,
alleging tortious interference with contract for failure to pay
installments due LESOP debenture holders. On April 2, 1993, the
Corporation filed an answer to the complaint and, on May 14, 1993, filed a
motion in the Bankruptcy Court for summary judgment to dismiss this action
which is still pending.
Security Holder Litigation
After the announcement on June 19, 1991, regarding the Corporation's
probable charge to second quarter earnings and the suspension of its
dividend, 17 complaints including purported class actions were filed
against the Corporation and its directors and certain officers of the
debtor companies in the U.S. District Court of Delaware. The actions,
which generally allege violations of certain antifraud provisions of the
Securities Act of 1933 and the Securities Exchange Act of 1934, have been
consolidated. In addition, three derivative actions were filed in the
Court of Chancery in and for New Castle County (Delaware) alleging that
directors breached their fiduciary duties.
23
24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
These suits have been stayed by either the Bankruptcy Court filing or by
stipulation of the parties. While the Corporation believes that it has
meritorious defenses to these actions, the outcome is uncertain at this
time.
Customer Refunds
In July 1993, the U.S. Court of Appeals for the Third Circuit overturned
most of a U.S. District Court ruling and affirmed an earlier Bankruptcy
Court decision that refunds Columbia Transmission received from upstream
pipelines, as well as the Gas Research Institute (GRI) surcharge payments
it collected from customers, are held in trust, by Columbia Transmission,
for those customers and the GRI and are not part of Columbia Transmission's
estate. In August 1993, the Third Circuit denied the Columbia Transmission
Creditors' Committee's request for a rehearing. In February 1994, the
Supreme Court denied petitions for review of the Third Circuit decision.
Under the Third Circuit ruling, approximately $173 million in refunds that
Columbia Transmission has received, or expects to receive postpetition from
upstream pipelines and GRI surcharges collected should be passed through to
the customers and to the GRI. In addition, the Third Circuit determined
that $35 million in upstream pipeline refunds and GRI surcharges, which
Columbia Transmission collected prior to filing Chapter 11 while received
in trust, were subject to the "lowest intermediate cash balance test" (the
amount remaining in trust at the time of bankruptcy) and should be
distributed on a pro rata basis to the customers and to the GRI to the
extent of Columbia Transmission's $3.3 million cash balance on July 31,
1991. The Third Circuit affirmed another part of the U. S. District
Court's decision and held that approximately $16 million that Columbia
Transmission owes upstream suppliers, for gas purchased and transportation
services received prior to its bankruptcy filing, is ordinary unsecured
debt which must be discharged in the bankruptcy process.
On February 10, 1994, the District Court issued an order for the Bankruptcy
Court to pursue further proceedings in accordance with the Third Circuit's
refund decision directing the pass-through of these refunds. At a hearing
on December 29, 1993, the Bankruptcy Court observed that the Federal Energy
Regulatory Commission (FERC) should determine whether customers are
entitled to the actual interest earned on refunds being held by Columbia
Transmission or the higher FERC-prescribed interest rate. On February 18,
1994, Columbia Transmission filed a motion with the FERC for determination
of this interest issue. Columbia Transmission will ask the Bankruptcy
Court for implementation of the mandate. Columbia Transmission will also
have to file with the FERC to reimplement its flow-through of Order Nos.
500/528 refunds from its pipeline suppliers, which represent the majority
of the refunds at issue. It is anticipated that Columbia Transmission will
recommence the flow-through of the upstream pipeline refunds in 1994.
Total customer claims in Columbia Transmission's bankruptcy proceedings
relating to, or arising from, Columbia Transmission's contracts with its
customers for sales, transportation, gas storage and similar services and
other miscellaneous claims represent about 450 claims for a total of
approximately $550 million as filed, plus a potentially substantial sum
filed in undetermined amounts. Columbia Transmission successfully resolved
a significant portion of these customer claims. Not resolved are customer
claims that total approximately $113 million at December 31, 1993, that
seek to protect rights associated with any prepetition revenues collected
subject to refund in general rate filings and purchased gas adjustment
filings, including matters subject to court appeals. In addition, the
claims filed in undetermined amounts, which potentially could be
significant, still remain to be resolved. In October 1993, approximately
$160 million was refunded to customers by Columbia Transmission reflecting
the terms of a settlement of a 1991 rate case approved by the Bankruptcy
Court in July 1993. Bankruptcy Court approval for a 1990 rate case
settlement for rates in effect from November 1, 1990 through November 30,
1991 was deferred pending the decision by the Third Circuit regarding the
flow-through of certain refunds. Appropriate reserves for rate refund
liabilities have been recorded for these matters to reflect management's
judgment of the ultimate outcome of the proceedings.
24
25
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Customer Recoupment Rights
During the fourth quarter of 1993, various customers of Columbia
Transmission filed motions with the Bankruptcy Court seeking authority to
exercise alleged recoupment and setoff rights, whereby they would be
permitted to reduce amounts owed to Columbia Transmission against refunds
owed to the customers by Columbia Transmission, including amounts which
were not otherwise payable in full under the above-mentioned July 1993
Third Circuit decision, all customer refunds under the 1990 rate case
settlement and miscellaneous refunds not otherwise payable in full to them.
Customers are alleging that they have recoupment and setoff rights of
approximately $83 million at December 31, 1993.
On October 20, 1993, the Bankruptcy Court approved an interim settlement
under which customers continued to pay Columbia Transmission for
FERC-authorized services at authorized rates, and Columbia Transmission has
agreed to grant these customers a priority claim to the extent the
Bankruptcy Court finds them entitled to recoupment rights. In January
1994, the Bankruptcy Court issued a procedural order whereby other
customers would be permitted to file recoupment and setoff motions by
February 18, 1994, with a trial on all such motions scheduled for June
1994.
Interest Expense
Interest expense of the Corporation is not being accrued during bankruptcy
but a calculation of interest is included in a footnote on the Statements
of Consolidated Income and Consolidated Balance Sheets. Such interest has
been calculated based on management's interpretation of the contractual
arrangements which govern the various debt instruments the Corporation has
outstanding exclusive of any redemption premiums. The Official Committee
of Unsecured Creditors of the Corporation (Committee) has asserted claims
for interest which exceed disclosed amounts by approximately $40 million at
December 31, 1993. There are several factors to be considered in making
these calculations that are subject to uncertainty as to their ultimate
outcome in the bankruptcy proceeding, including the interest rates and
method of calculation to be applied to overdue payments of principal and
interest. In addition, the Committee has asserted that approximately $110
million of redemption premiums should be paid on high cost debt
instruments.
25
26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
OIL AND GAS OPERATIONS
Market Conditions
Natural gas markets showed renewed strength in 1993, responding to seasonal
weather conditions and uncertainty regarding the availability of supplies
in the new operating environment brought about by FERC Order No. 636 (Order
636). Overall for 1993, natural gas prices averaged $2.28 per Mcf compared
to $2.02 in 1992. Oil prices continued their decline from a 1992 level of
$18.20 per barrel to $16.17 per barrel for 1993.
Capital Expenditures
The 1993 capital expenditure program increased to $95 million from the $71
million level in 1992. The 1993 program provided for increased development
drilling and a modest exploration program in the southwest.
In the southwest, Columbia Gas Development Corporation (Columbia
Development) experienced an increase in both gas and oil production in
1993, reflecting the continuing success of its drilling program, especially
its horizontal drilling program in the Austin Chalk Trend in Texas. During
the fourth quarter of 1993, Columbia Development drilled and completed its
100th horizontal well in that area. Major reconditioning work in early
1993 also contributed to the increase in production.
During 1993, 87 gross (46 net) wells were drilled with a 69 percent success
rate. Of these, 47 were drilled in the Austin Chalk, 94 percent of which
were successful. Productivity was enhanced by an increased emphasis on
dual lateral wells (multiple lateral wells drilled from a single vertical
well). The 44 successful wells drilled included 70 laterals. This
substantially increased production while reducing overall cost per well,
since the costs of the vertical portion of each well were shared by more
than one lateral and the combined laterals accessed a larger area. In
1992, 30 wells with 38 laterals were drilled.
Horizontal wells drilled in the Austin Chalk formation during 1993 tested
at average daily rates ranging from 250 to 1,040 barrels of oil and 550,000
to 3.1 million cubic feet of gas. Columbia Development holds varying
interests in these wells. Development drilling continues in the South
Harmony Church area in southern Louisiana. In 1993, three successful wells
in this area, 100 percent owned by Columbia Development, tested at combined
rates of seven million cubic feet of gas and 925 barrels of oil per day.
In the Appalachian area, CNR's 1993 development well program totaled 120
gross (75 net) wells, with a success rate of 89 percent. One of the most
promising areas under development is a formation underlying existing
production in Ohio, known as Rose Run. CNR has been producing in this
formation in recent years with excellent results. Favorable reservoir
characteristics allow Rose Run prospects to quickly generate a return on
invested capital. CNR's 1994 development program will continue to target
several prospects in this area.
The oil and gas segment's total 1994 exploration and development program of
$91 million will continue to focus primarily on development drilling while
maintaining the modest level of the 1993 exploration program. Because of
weak oil prices the Corporation has adopted more conservative guidelines
for economic evaluations to reduce risk.
Reserves
Net proved natural gas reserves at the end of 1993 totalled 697 Bcf,
compared to 779.5 Bcf at the end of 1992. Proved oil, condensate and
natural gas liquids decreased from 14.7 million barrels at the end of 1992
to 12.8 million barrels at the end of 1993. The year end drop in oil
prices accounted for approximately 0.6 million barrels of the decline by
rendering some properties uneconomical. Increased oil prices would result
in recovery of those reserves.
As a result of a year end decline from 1992 to 1993 in gas prices together
with an increase in lifting costs, the
26
27
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
recoverable gas reserves for CNR were revised downward 65.9 Bcf (11
percent). Without this reduction, newly discovered reserves and extensions
approximately equaled production. In addition, Columbia Development's
Huntington Beach oil recovery waterflood project has shown disappointing
production during 1993, resulting in revised reserve estimates of 1.1
million barrels, down 1.6 million barrels from 1992. Geological and
engineering analysis of the project is continuing.
Current pricing has enhanced the profitability of gas prospects, and these
prospects are the focus of the 1994 capital program.
Royalty Dispute
Columbia Development is involved in a $14 million royalty dispute with the
U.S. Minerals Management Service (MMS) regarding royalty valuation issues
in connection with prior sales to an affiliate. As a result of an
unfavorable lower-court decision regarding the statute of limitations, a
pre-tax reserve of $5.4 million has been established by Columbia
Development. Based on information currently available, management believes
this reserve to be adequate; however, the contested matters are under
review, and management is currently negotiating a settlement with the MMS.
Proposed Rulemaking for Offshore Drilling Financial Responsibility
The MMS has issued an advance notice of proposed rulemaking for oil spill
financial responsibility that would establish financial responsibility at
$150 million for all operators of offshore facilities and facilities in,
on, or under the navigable waters of the United States.
Regulations currently require operators to demonstrate financial
responsibility of up to $35 million in liability coverage. Both Columbia
Development and CNR operate in navigable waterways covered under the
proposed regulations. The insurance industry has indicated an
unwillingness to meet the proposed financial responsibility due to certain
proposed provisions contained in the rulemaking. Many comments have been
received by the MMS critical of this rulemaking and its new financial
responsibility requirement as well as other provisions. Since final rules
may be at least two years away, it is impossible to determine the
implications for the Corporation's oil and gas operations.
Volumes
Gas production totalled 71.5 Bcf in 1993, an increase of 3 percent over
1992. The increase includes new Southwest offshore production and new
onshore production in Texas, south Louisiana and New Mexico. This
improvement was tempered by a small decrease in production due to
construction and maintenance activities on pipelines and compressors
serving Columbia's Appalachian production area. After adjusting for the
1991 sale of the Canadian operations, gas production for 1992 was
essentially unchanged from the previous year.
Oil and liquids production in 1993 of 3,603,000 barrels reflected an
increase of nearly 18 percent compared to 1992 due largely to the success
of the Southwest program. Production for 1992, after adjusting for the
sale of the Canadian operations, increased 228,000 barrels over 1991.
Operating Revenues
Higher gas prices together with increases in oil and gas production led to
operating revenues of $222.2 million in 1993, an increase of 12 percent
over 1992. Dampening these improvements was the lower average price for
oil and liquids and the $5.4 million reserve for the royalty dispute
discussed above.
The sale of the Canadian subsidiary was the primary reason for 1992
operating revenues to decrease $16.1 million from 1991, or 7 percent. The
decline was somewhat offset as the average gas price in 1992 was $2.02 per
Mcf, 7 percent higher than 1991, after adjusting for the 1991 sale of the
Canadian operations. The average price for oil
27
28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
and liquids in 1992 of $18.20 per barrel represented a decline of 18
percent from the price for domestic production the previous year.
Operating Income (Loss)
Operating income of $53.6 million in 1993 compares to an operating loss of
$101.2 million in the prior year which was due largely to recording a
writedown in the carrying value of oil and gas properties of $126.4 million
due to depressed energy prices. The current period improvement in
operating income also reflected higher operating revenues and lower
depletion expense. These improvements were partially offset by higher
operation and maintenance expense for costs related to new wells and
additional reconditioning work on older wells.
The $96.7 million additional operating loss in 1992 compared to 1991
resulted from the effect of the writedown mentioned above together with
higher operating expenses. These declines were mitigated by writedowns
incurred in 1991 for the Canadian properties.
28
29
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM OIL AND GAS OPERATIONS (UNAUDITED)
Year Ended December 31 (in millions) 1993 1992 1991*
---------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Gas $163.8 $ 143.1 $142.6
Oil and liquids 58.4 55.6 72.2
---------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 222.2 198.7 214.8
---------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 83.7 78.7 78.3
Depreciation and depletion 73.8 210.0 130.1
Other taxes 11.1 11.2 10.9
---------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 168.6 299.9 219.3
---------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME (LOSS) $ 53.6 $(101.2) $ (4.5)
---------------------------------------------------------------------------------------------------------------------------
* Includes results from Canadian operations that were sold effective
December 31, 1991.
OIL AND GAS OPERATING HIGHLIGHTS*
1993 1992 1991 1990 1989
---------------------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 95.1 70.8 120.8 229.0 147.9
---------------------------------------------------------------------------------------------------------------------------
PROVED RESERVES
Gas (Bcf) 697.0 779.5 808.1 925.7 902.7
Oil and Liquids (000 barrels) 12,792 14,650 15,568 18,991 16,731
---------------------------------------------------------------------------------------------------------------------------
PRODUCTION
Gas (Bcf) 71.5 69.2 76.3 75.3 77.7
Oil and Liquids (000 barrels) 3,603 3,061 3,411 2,688 1,924
---------------------------------------------------------------------------------------------------------------------------
AVERAGE PRICES
Gas ($ per Mcf) 2.28 2.02 1.81 2.00 1.89
Oil and Liquids ($ per barrel) 16.17 18.20 21.10 22.86 16.71
---------------------------------------------------------------------------------------------------------------------------
* Years 1991 through 1989 include results from Canadian operations that
were sold effective December 31, 1991.
29
30
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
TRANSMISSION OPERATIONS
Operations
The transportation and storage rates of Columbia Transmission and the
transportation rates of Columbia Gulf Transmission Company (Columbia Gulf)
are currently among the most competitive serving the companies' general
market areas. The companies are committed to maintaining their competitive
position on an ongoing basis through a combination of efficient and
effective maintenance of existing facilities, economical new market
development and a commitment to the highest level of overall customer
satisfaction.
Columbia Transmission recently received an order from the FERC for the
construction of the Rutledge Compressor Station in Harford County,
Maryland. This station will allow Columbia Transmission to transport
53,400 Mcf per day to the Eagle Point Cogeneration Plant in New Jersey and
over 58,000 Mcf per day to New England Power. It is anticipated that the
Rutledge Compressor Station will be in service by December 1994.
Columbia Transmission will provide approximately 52,000 Mcf per day of
interruptible transportation service to Gordonsville Energy Limited
Partnership, an independent power producer in Louisa County, Virginia, in
late summer of 1994.
Rate Cases
Columbia Transmission's and Columbia Gulf's rates are subject to the
jurisdiction of the FERC. These transmission companies (Transmission) make
periodic filings for rate changes to recover costs associated with new
facilities, operating and capital costs, and to reflect changes in
throughput, cost allocation or rate design. Settlements of issues related
to these filings are subject to approval by the FERC, and with respect to
Columbia Transmission during its bankruptcy, the Bankruptcy Court.
During 1993, Columbia Transmission and Columbia Gulf sought approval of two
rate settlements. As previously reported, a 1990 rate filing by both
companies covering the period November 1, 1990 through November 30, 1991,
received FERC approval in 1992; however, Bankruptcy Court approval for
Columbia Transmission to make refunds has been delayed pending resolution
of certain motions filed by various creditors.
Columbia Transmission and Columbia Gulf received FERC and Bankruptcy Court
approvals for a settlement of a general rate case that went into effect on
December 1, 1991. Two parties continue to contest certain aspects of the
settlement. Columbia Transmission and Columbia Gulf have made refunds and
implemented rates prescribed to all parties consenting to this settlement.
The nonconsenting parties, for whom separate proceedings are expected to be
scheduled soon, have challenged the FERC's order and have filed a court
appeal. In management's opinion, the outcome of the legal proceedings with
the nonconsenting parties, including the above mentioned court appeal, will
not have a material adverse impact on the Corporation.
WACOG Surcharge
Under the terms of a 1985 settlement with its customers, Columbia
Transmission is entitled to impose a sales commodity surcharge when its
weighted average cost of gas (WACOG) met certain conditions. These
conditions were met in 1992, and Columbia Transmission was authorized to
include the surcharge in its rates for the period September 1, 1993 through
August 31, 1994. Under Order 636, which became effective November 1, 1993,
Columbia Transmission essentially eliminated its merchant function and
proposed an alternative method of recovering these costs which the FERC
conditionally accepted.
In January 1994, Columbia Transmission filed a settlement with the FERC
resolving all issues relating to this unrecovered surcharge. The
settlement permits Columbia Transmission to continue collecting a surcharge
on transportation volumes through October 1994, that would result in the
opportunity to collect approximately $42.8 million in additional revenues.
30
31
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Order No. 636
During 1993, Columbia Transmission and Columbia Gulf implemented the
restructured services mandated by the FERC's Order 636. Columbia
Transmission has virtually eliminated its merchant function and now offers
a variety of unbundled storage and transportation services. In order to
implement this restructuring, the companies made a series of filings with
the FERC reflecting changes in rates and the terms and conditions under
which services would be offered.
On October 22, 1993, Columbia Transmission and Columbia Gulf made their
final compliance filing before implementing restructured services, under
Order 636, on November 1, 1993. In this filing, the companies complied
with previous FERC orders and made various revisions to the terms and
conditions applicable to their restructured transportation and storage
services. In December 1993, the FERC issued an order on rehearing that
permitted Columbia Transmission to retain in its rates, costs which the
FERC had previously determined were associated with its merchant function,
and approved the level of costs that Columbia Transmission proposed to be
allocated to interruptible transportation service.
In the series of orders issued in Columbia Transmission's Order 636
proceeding, the FERC addressed issues related to Columbia Transmission's
ability to recover transition costs. The FERC determined that costs
incurred by Columbia Transmission as a result of rejecting producer gas
supply contracts, in its bankruptcy proceeding in 1991, were not eligible
for recovery as Gas Supply Realignment (GSR) costs under Order 636. In
addition, recovery of these costs pursuant to Orders 500 and 528 was
prohibited by the terms of a 1989 customer settlement. The FERC determined
that Columbia Transmission could recover certain contract rejection costs
through its existing Gas Inventory Charge (GIC), but only to the extent
such costs were not incurred during the 1991 contract year, a period in
which Columbia Transmission did not meet the qualifying competitive test
under the GIC. If upheld, the FERC rulings, which are subject to pending
court review, effectively preclude Columbia Transmission from recovering a
significant portion of the producer contract rejection costs from its
customers.
The FERC has generally acknowledged Columbia Transmission's right to seek
recovery of other types of transition costs. The FERC approved Columbia
Transmission's proposal to recover certain purchased gas costs that were
incurred prior to Order 636 restructuring. It also agreed to waive a
nine-month time limit on Columbia Transmission's ability to seek recovery
of unrecovered purchased gas costs to the extent the costs resulted from
contracts that are currently in litigation, including bankruptcy
litigation. Approximately $60 million in unrecovered purchased gas costs
were outstanding at December 31, 1993, in addition to approximately $140
million of prepetition unrecovered purchased gas costs that have not been
paid due to the bankruptcy filing.
The FERC also addressed Columbia Transmission's ability to recover costs
associated with upstream pipeline contracts. Columbia Transmission
currently holds firm transportation agreements with certain pipeline
companies that historically have been used to deliver gas to Columbia
Transmission. These contracts have remaining terms of various lengths and
require the payment of monthly reservation fees whether or not the capacity
is utilized. Under Order 636, downstream pipelines such as Columbia
Transmission are required to offer to assign most of their firm upstream
capacity to their customers. Columbia Transmission's annual demand charge
commitments on these upstream non-affiliated pipelines was approximately
$108 million; however, assignments of certain of these contracts by
Columbia Transmission to its customers in conjunction with service
restructuring under Order 636 have reduced this amount to less than $74
million. The total commitment for demand charges after November 1, 1993,
is approximately $421 million on an undiscounted basis, excluding any
mitigating effect of the pipelines marketing the capacity to others.
Subject to review in connection with periodic rate filings, the FERC
approved Columbia Transmission's proposal to continue to recover costs
associated with retained upstream pipeline contracts through its demand
rates. Recovery of such costs would be subject to review and approval in
semiannual limited rate filings. Columbia Transmission
31
32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
has reached settlements that will eliminate approximately half of the
annual cost of these contracts and is continuing its efforts to negotiate a
mutually agreeable termination of the remainder of the contracts.
Columbia Transmission's strategy has been to assume all upstream pipeline
contracts that can be directly assigned to its customers or need to be
retained by Columbia Transmission for operational reasons and negotiate
exit fees for other upstream contracts. The FERC ruling in the Order 636
proceedings permits recovery of these exit fees through rates, provided
that Columbia Transmission can show that they are prudently incurred.
Columbia Transmission retains the option of rejecting such contracts in its
bankruptcy proceedings, if appropriate exit fees cannot be negotiated.
The financial statements reflect a $130 million liability and offsetting
receivable for the exit fee issue; however, the ultimate cost could vary
depending on the outcome of ongoing discussions with the affected
pipelines.
Several settlements with upstream pipelines have been concluded. In 1993,
the Bankruptcy Court approved settlements between Columbia Transmission and
Texas Eastern Transmission Corporation, Panhandle Eastern Pipe Line Company
and Texas Gas Transmission Corporation which provide for assumption of
certain contracts and termination of others. None of these settlements
required Columbia Transmission to pay an exit fee to the upstream pipeline.
In November 1993, the Bankruptcy Court approved a settlement between
Columbia Transmission and Tennessee Gas Pipe Line Company (Tennessee).
This settlement provides for Columbia Transmission's assumption of certain
contracts, the termination of certain other contracts that are no longer
necessary for Columbia Transmission's operations and payment to Tennessee
of approximately $42 million in consideration for Tennessee's substantial
reduction of its major transportation contracts with Columbia Transmission.
On January 11, 1994, Columbia Transmission and Tennessee made a filing at
the FERC to approve the settlement. Columbia Transmission expects to
ultimately recover the costs and fees associated with the assumption and
termination of these contracts under Order 636. The Tennessee settlement
agreement is conditioned upon this recoverability.
The FERC affirmed that Columbia Transmission could continue its existing
rate structure to recover costs associated with its gathering facilities
through its gathering and other transportation rates until it files a
general rate case. Management continues to evaluate the long-term plans
for Columbia Transmission's gathering facilities which have a net book
value of approximately $63 million at December 31, 1993. The regulatory
treatment of gathering facilities is currently the subject of a generic
FERC proceeding. While the ultimate outcome of issues related to
realization of its investment in gathering facilities is uncertain at this
time and future charges to income may be required, management believes that
substantially all of these costs will be recovered through rates or sale of
the facilities.
As part of its September 29, 1993 order on Columbia Transmission's and
Columbia Gulf's Order 636 compliance filings, the FERC initiated a
proceeding concerning Columbia Gulf's transportation service to Columbia
Transmission. Columbia Gulf was directed to show cause as to why it has
not filed for FERC abandonment authorization to reduce capacity and service
to Columbia Transmission as required under the Natural Gas Act. Columbia
Gulf responded to the show cause order on December 22, 1993. Management
does not believe an abandonment filing was necessary and does not expect
the resolution of this issue to have a material adverse effect on the
Corporation's financial position.
One type of transition cost which the FERC acknowledged would be eligible
for recovery consideration is "stranded costs", which are the costs of a
pipeline's assets previously used to provide bundled sales service in the
pre-Order 636 era and are unsubscribed in the Order 636 environment.
Columbia Gulf has several pipelines and related facilities that are not
fully subscribed to under Order 636. Certain facilities south of Rayne,
Louisiana (primarily in the offshore Gulf of Mexico area), are being
evaluated; however, management has not identified any stranded facilities
at this time and the outcome of these evaluations is uncertain. Dependent
upon the results of such evaluation, charges to income could be required.
The net book value of the facilities under study was approximately $40
million at December 31, 1993. It is management's view that any costs
associated with these facilities will be fully recoverable through rates.
Order 94 Settlements
On January 12, 1994, the FERC granted requests for rehearing of prior
orders approving settlements between
32
33
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Columbia Transmission and four of its upstream pipeline suppliers relating
to those suppliers' direct billings to Columbia Transmission of the FERC's
Order 94 (Order 94) costs in the mid-1980s. The rehearing orders found
that the settlements must be rejected because they are expressly contingent
upon Columbia Transmission's recovery of the Order 94 settlement payments
from its customers and Columbia Transmission's 1985 PGA Settlement
essentially bars such recovery. The orders also hold that these pipelines
are not entitled to bill any Order 94 charges to Columbia Transmission.
The FERC ordered these upstream pipelines to refund the principal amounts
of all Order 94 collections from Columbia Transmission, but waived any
requirement that these pipelines pay interest on the refunds. Since
Columbia Transmission has been reflecting the interest income on these
refunds since 1990, these orders led to a $19.5 million reduction to
interest income in 1993. Columbia Transmission has sought rehearing and,
if necessary, will seek court review of these orders. It is expected that
pipeline suppliers will also request rehearing arguing their rights to
re-bill such charges to Columbia Transmission. The ultimate outcome of
this issue is uncertain at this time and could impact future operating
results depending upon the results of these additional regulatory and court
reviews.
Environmental Matters
Columbia Transmission and Columbia Gulf are subject to extensive federal,
state and local laws and regulations relating to environmental matters.
These laws and regulations, which are constantly changing, require
expenditures for corrective action at various operating facilities and
waste disposal sites for conditions resulting from past practices that
subsequently were determined to be environmentally unsound.
The transmission subsidiaries have received notice from the United States
Environmental Protection Agency (EPA) that they are among several parties
responsible under federal law for placing wastes at Superfund sites and may
be required to share in the cost of remediation of these sites. However,
considering known facts, existing laws and possible insurance and rate
recoveries, management does not believe the identified Superfund matters
will have a material adverse effect on future income or on the
Corporation's financial position.
The transmission subsidiaries are continuing their comprehensive review of
compliance with existing environmental standards, including review of past
operational activities and identification of potential site problems,
through site reviews and formulation of remediation programs where
necessary. The transmission subsidiaries have made progress in these
ongoing self- assessment programs. However, because of the thousands of
miles of pipeline which they operate, the exceptionally large number of
sites at which they conduct or have conducted operations, and the long
period over which operations have been conducted, completion of site
screenings, characterizations and site-specific remediations will require
approximately 10 to 12 years. All environmental agencies have been
declared exempt from the Bar Date established by the Bankruptcy Court for
claims by creditors.
A study for Columbia Transmission to quantify the scope of remediation
activities which will be undertaken in future years to address the issues
identified was recently concluded. This study, site investigations and
characterization efforts performed throughout 1993, resulted in total
accruals for the year of approximately $60 million for Columbia
Transmission. These and other minor adjustments bring Columbia
Transmission's recorded net liability to $143.6 million at December 31,
1993. This represents the lower end of the range of reasonable outcomes
with the upper end estimated to total approximately $280 million based on
information currently available.
As characterization and site-specific activities by Columbia Transmission
determine the nature and extent of contamination at its facilities and as
remediation plans are developed, additional charges to earnings could
occur. To the extent such plans require approval of federal and/or state
authorities, estimates are subject to revision. Based on the limited data
now available and various assumptions as to characterization and
remediation, management believes that annual future expenditures for
Columbia Transmission's site investigations, characterization and
remediation activities could be up to $20 million per year over a 10- to
12- year time frame. Since the transmission companies do not account for
their operations under SFAS No. 71, earnings will continue to be charged as
costs become probable and reasonably estimable, regardless of when
expenditures are made.
33
34
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
As a result of site characterization studies at various locations during
1993, Columbia Gulf recorded an additional accrual of $6.7 million for
environmental remediation. This accrual is for polychlorinated biphenyl
(PCB) cleanup and hydrocarbon spills at certain compressor station sites
and screenings for possible exposure at other locations. Columbia Gulf
anticipates completion of cleanup during 1994. At that time, costs of
remediation, if any, will be quantified, and an additional accrual may
become necessary.
In 1992, Columbia Transmission received a subpoena and information request
(Request) from the EPA Region III regarding three major environmental
statutes: The Toxic Substance Control Act (TSCA), the Resource
Conservation and Recovery Act (RCRA), and the Comprehensive Environmental
Response Compensation and Liability Act (CERCLA). The Request relates to
Columbia Transmission's past and current environmental practices. Since
receipt of the Request, Columbia Transmission has provided the EPA with
substantial materials regarding the Request. Columbia Transmission
continues to meet with the EPA to attempt to resolve the subpoena issues,
including related fines and penalties, which it believes will be resolved
in the near future.
Columbia Transmission on January 28, 1994 received from EPA Region V an
Information Request pursuant to RCRA. The agency requested Columbia
Transmission to submit information and knowledge relating to its generation
and management of natural gas pipeline condensate, used engine oil and
similar liquids in the state of Ohio. Columbia Transmission is in the
process of analyzing the information requested and will be discussing this
Information Request with EPA Region V.
It is management's continued intent to address environmental issues in
cooperation with regulatory authorities in such a manner as to achieve
mutually acceptable compliance plans. However, there can be no assurance
that fines and penalties will not be incurred by Columbia Transmission and
Columbia Gulf.
The eventual total cost of full future environmental compliance for
Columbia Transmission and Columbia Gulf is difficult to estimate due to,
among other things: (1) the possibility of as yet unknown contamination;
(2) the possible effect of future legislation and new environmental agency
rules; (3) the possibility of future litigation; (4) the possibility of
future designations as a potentially responsible party by the EPA and the
difficulty of determining liability, if any, in proportion to other
responsible parties; (5) possible insurance and rate recoveries; and (6)
the effect of possible technological changes relating to future
remediation.
Management expects most environmental assessment and remediation costs to
be recoverable through rates or insurance. Although significant charges to
earnings could be required prior to rate recovery, management does not
believe that environmental expenditures will have a material adverse effect
on the Corporation's financial position based on known facts, existing laws
and regulations and the period over which expenditures are required.
Clean Air Act Amendments of 1990
Columbia Transmission and Columbia Gulf have completed preliminary studies
to determine the impact of the Clean Air Act Amendments of 1990 (CAA-90).
The studies focused on various compressor facilities for both companies.
The facilities are among those affected by the new nitrogen oxide emission
standards under CAA-90. It is estimated that capital expenditures
necessary to comply with these new standards could be in excess of $30
million over the next few years. However, due to the preliminary nature of
the studies, the uncertainty of individual state regulations and other
variables, the actual amount of future expenditures related to CAA-90 is
difficult to estimate. Management anticipates that all capital
expenditures made in compliance with CAA-90 will be recoverable through the
rate-making process. Operation and maintenance expenses, including
monitoring of emissions and permit fees, could approximate $5 million to
$10 million per year for the transmission companies.
Partnership Issues
Columbia Gulf is a general partner in the Trailblazer, Overthrust and Ozark
pipeline partnerships. Since these partnerships are nonrecourse
project-financed pipelines, the partnerships' firm shipper contracts were
assigned to various banks (or in the case of Ozark, to the Indenture
Trustee) as collateral for loans.
34
35
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Columbia Transmission and other shippers are attempting to negotiate exit
fees under Order 636 with the partnerships. As a result of these
negotiations and the current depressed demand for capacity in certain of
the partnerships, the realizability of these investments is uncertain, and
a valuation reserve of $5.4 million was established in 1993. It is not
expected that these issues will be resolved until late 1994. At December
31, 1993, Columbia Gulf's investment in the partnerships amounted to $35.4
million, net of the valuation reserve and before related deferred taxes.
Cove Point LNG Terminal
As previously reported, Columbia LNG Corporation (Columbia LNG) has
developed a new business plan to reactivate the Cove Point facility.
Originally this plan anticipated a new peaking and storage service by the
end of 1994, as well as a terminalling service for liquefied natural gas
(LNG) received by tanker. However, that plan has been modified to where
now only a peaking service will be offered initially. As a consequence,
Columbia LNG recorded a writedown in the carrying value of its investment
in the Cove Point facility in the second quarter 1993 that reduced the
Corporation's income by $37.9 million after-tax. This amount included
estimated dismantling costs for the offshore facilities of approximately
$12 million after-tax. Until transferred to the new partnership, as
discussed below, Columbia LNG plans to maintain the offshore facilities for
possible future imports and at the present time has no plans to abandon or
dismantle them.
A partnership between Columbia LNG and a wholly-owned subsidiary of Potomac
Electric Power Company was formed in October 1993. The partnership, which
is pursuing Columbia LNG's business plan filed an application with the FERC
on November 3, 1993, seeking authorization to acquire all of the existing
plant and pipeline facilities owned by Columbia LNG and for authorization
to recommission the plant and construct new facilities in order to provide
peaking services beginning in 1995. In addition to the FERC, this
transaction will require other governmental approvals. Bankruptcy Court
approval was received in January 1994.
The realization of the Corporation's remaining investment in Columbia LNG
of $10.1 million will be dependent upon successful implementation of the
partnership and the related business plan.
Volumes
Throughput for Transmission includes tariff sales and transportation
service to local distribution companies (LDCs) and other customers in
Columbia Transmission's market area, Columbia Gulf's main line
transportation service from Louisiana to West Virginia and Columbia Gulf's
short-haul transportation service primarily from the Gulf of Mexico to
Rayne, Louisiana. Transmission's throughput in 1993 was 1,355.9 Bcf, a
decrease of 18.4 Bcf from 1992. In 1992, throughput increased 144.8 Bcf
over 1991 to 1,374.3 Bcf.
A decrease of 13.1 Bcf in market area transportation between 1993 and 1992
was due primarily to the one-time arrangement in 1992 in which customers
used market area transportation to repay certain gas delivered to them
during the 1990 - 1991 winter season by Columbia Transmission. Throughput
losses not associated with prior period activity also occurred primarily
due to competition from other pipelines that began operating under Order
636 (or a modified version thereof) earlier this year. As expected, this
load loss began to reverse following Columbia Transmission's implementation
of Order 636 in November 1993, when its transportation rates became more
competitive. This effect was partially offset by a throughput improvement
resulting from customers using firm transportation services for delivering
gas withdrawn from storage during 1993. In 1992, customers' increased use
of Columbia Transmission's firm storage service (FSS) led to an increase of
59.1 Bcf in market area transportation from the year before.
Columbia Gulf's 1993 mainline transportation service increased 5.6 Bcf from
1992 and between 1992 and 1991 increased by 38.9 Bcf. These increases
primarily reflect additional transportation services for customers to move
gas to Columbia Transmission's storage under its FSS agreement and to meet
their supply requirements. Prior to the implementation of Order 636, a
portion of Columbia Gulf's mainline capacity was reserved for Columbia
Transmission's use for deliveries to LDCs and other markets. Beginning on
November 1, 1993, however, Columbia Gulf's capacity was assigned to LDCs
and end users.
35
36
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Short-haul transportation has been increasing in recent years, reflecting
additional arrangements made by marketers and customers for delivery of
lower-priced spot market gas. In 1993, short-haul transportation was
essentially unchanged from last year and reflected an increase of 60.3 Bcf
between 1992 and 1991.
Sales volumes for 1993 decreased 12.3 Bcf from 1992 due primarily to the
implementation of Order 636. This decrease was partially offset by colder
weather in the current period and the timing of prepaid gas sales.
Comparing 1992 to 1991, sales increased 83.4 Bcf reflecting 10 percent
colder weather, timing changes for prepaid gas sales and Columbia
Transmission's competitive market-sensitive commodity rate, that resulted
from the rejection in Bankruptcy Court of noncompetitive above-market gas
purchase contracts.
Net Revenues
Transmission's 1993 net revenues of $841.5 million increased $80.1 million
over 1992. Included in 1993's net revenues are $20.3 million associated
with the recovery through Columbia Transmission's WACOG surcharge, as
discussed previously, and GIC revenues of $20.8 million. 1992 GIC revenues
were $20.9 million. The GIC mechanism allowed Columbia Transmission to
charge a fee to customers whose purchases fell below a pre-determined level
provided Columbia Transmission's cost of gas meets a comparability test
with competing pipelines. Also improving 1993 net revenue was an
adjustment to rate refund reserves and the favorable effect of normal
weather. These effects combined with the benefit of the full year effect
of Columbia Transmission's new rate design where a greater portion of its
fixed costs are recovered through a monthly demand charge more than offset
the recording of a loss on the sale of storage inventory.
Net revenues for 1992 increased to $761.4 million, up $126.9 million over
1991 principally reflecting improved rate design together with higher
throughput and GIC revenues.
Operating Income (Loss)
Operating income for 1993 of $178.7 million, increased $48.8 million over
1992. Higher net revenues together with a 1992 provision for gas supply
costs combined to more than offset the effect of recording a second quarter
1993 writedown of $57.5 million for the investment in the Cove Point LNG
facility (See Note 12F in Notes to Consolidated Financial Statements for
more information). Additional reserves for environmental costs of $66.8
million and $65.3 million were recorded in 1993 and 1992, respectively.
After adjusting for these and other unusual items, operating income would
have increased $37.8 million. These improvements more than offset higher
operating expenses, including increased labor and benefits costs due in
part to employee severance costs. These costs resulted from reengineering
Transmission's operations to improve the segment's efficiency and
effectiveness in the increasingly competitive natural gas industry.
Transmission's 1992 operating income of $129.9 million compares to a loss
of $1,192.2 million for 1991. The principal reason for the increase was
the 1991 provision for gas supply charges of $1,319.2 million. After
adjusting for bankruptcy and other unusual items, Transmission's operating
income would have improved $62.1 million in 1992 over 1991, due to
increased throughput and rate design changes.
36
37
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM TRANSMISSION OPERATIONS (UNAUDITED)
Year Ended December 31 (in millions) 1993 1992 1991
---------------------------------------------------------------------------------------------------------------------------
NET REVENUES
Sales revenues $1,027.2 $924.8 $ 609.2
Less: Cost of gas sold 724.9 654.4 391.0
---------------------------------------------------------------------------------------------------------------------------
Net Sales Revenues 302.3 270.4 218.2
---------------------------------------------------------------------------------------------------------------------------
Transportation revenues 633.2 449.0 430.8
Less: Associated gas costs 219.3 71.7 104.0
---------------------------------------------------------------------------------------------------------------------------
Net Transportation Revenues 413.9 377.3 326.8
---------------------------------------------------------------------------------------------------------------------------
Storage Revenues 125.3 113.7 89.5
---------------------------------------------------------------------------------------------------------------------------
Net Revenues 841.5 761.4 634.5
---------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Provision for gas supply charges - 38.6 1,319.2
Operation and maintenance 451.3 438.3 357.7
Depreciation 97.8 95.6 90.4
Other taxes 56.2 59.0 59.4
Writedown of investment in Columbia LNG Corporation 57.5 - -
---------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 662.8 631.5 1,826.7
---------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME (LOSS) $ 178.7 $129.9 $(1,192.2)
---------------------------------------------------------------------------------------------------------------------------
37
38
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
TRANSMISSION OPERATING HIGHLIGHTS
1993 1992 1991 1990 1989
--------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 137.2 114.2 152.9 279.5 189.5
--------------------------------------------------------------------------------------------------------------
THROUGHPUT (Bcf)
Transportation
Columbia Transmission
Market area 895.9 909.0 849.9 799.5 823.3
Columbia Gulf
Main-line 579.9 574.3 535.4 613.3 576.4
Short-haul 625.1 625.0 564.7 497.4 387.4
Intrasegment eliminations (928.7) (930.0) (833.1) (810.7) (647.4)
--------------------------------------------------------------------------------------------------------------
Total Transportation 1,172.2 1,178.3 1,116.9 1,099.5 1,139.7
Sales 183.7 196.0 112.6 89.2 408.2*
-------------------------------------------------------------------------------------------------------------
Total Throughput 1,355.9 1,374.3 1,229.5 1,188.7 1,547.9
--------------------------------------------------------------------------------------------------------------
SOURCES OF GAS FOR THROUGHPUT (Bcf)
Sources of Gas Sold
Spot market 148.5 66.3 1.9 20.1 1.1
Producers 65.3 106.7 152.3 227.7 232.0
Pipelines 1.9 - 0.5 4.7 16.0
Storage withdrawals (injections) 1.3 25.1 24.5 (175.6) 184.6
Exchange (2.2) 32.1 (37.8) 17.5 (14.5)
Other (31.1) (34.2) (28.8) (5.2) (11.0)
--------------------------------------------------------------------------------------------------------------
Total Sources of Gas Sold 183.7 196.0 112.6 89.2 408.2
Gas received for delivery
to customers 1,172.2 1,178.3 1,116.9 1,099.5 1,139.7
-------------------------------------------------------------------------------------------------------------
Total Sources 1,355.9 1,374.3 1,229.5 1,188.7 1,547.9
-------------------------------------------------------------------------------------------------------------
* Includes 116 billion cubic feet applicable to the sale of storage
inventory gas.
38
39
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
DISTRIBUTION OPERATIONS
Market Conditions
For the first time in four years, weather in the market area served by the
distribution companies (Distribution) was colder than normal. Weather was
only 1 percent colder than normal but 3 percent colder than last year, and
resulted in a 7.7 Bcf improvement in Distribution's weather sensitive
deliveries. In addition, relatively strong economic conditions throughout
Distribution's service territory, low interest rates, strong new housing
starts in several key market areas, and moderate unemployment, enabled
Distribution to add about 28,000 net residential and commercial customers
during the year, a 1.5 percent growth rate that tracks last year's growth
and compares favorably with the national average. Transportation
deliveries in 1993 increased 13.8 Bcf, 6.8 percent over 1992, reflecting
strong electric power generation demand and increasing industrial activity.
Distribution's electric competitors continue to pursue well-organized,
heavily funded strategic initiatives targeting markets such as space and
water heating. Electric companies in Distribution's markets are using a
variety of aggressive measures such as equipment leasing programs, rebates
and promotional incentives to make marketing inroads. These marketing
efforts have resulted in a reduction of approximately 0.6 percent in
Distribution's space heating load as a result of electric add-on heat pump
penetration and a 1.4 percent reduction in gas water heating saturation
since 1987. As a result, Distribution has been countering with its own
strategic programs such as equipment leasing, targeted advertising and
promotional activity that is designed to bolster Distribution's core
marketing and counter these negative competitive impacts.
Distribution's marketing strategy is to augment ongoing development of its
core residential, commercial, and industrial markets by pursuing
opportunities to develop new markets for natural gas in the areas of
natural gas vehicles (NGV), electric power generation and gas cooling.
Distribution is a leading participant in the gas industry's efforts to
promote NGVs as alternatives to conventionally fueled fleet and mass
transit vehicles. In March 1993, Columbia Gas of Ohio, Inc. (COH) opened
the nation's largest publicly accessible NGV fueling station in Columbus,
Ohio. Distribution operates five other publicly accessible stations and is
initiating a five-year program to establish approximately 100 additional
publicly accessible fueling sites throughout its service territory.
Distribution is also committed to maximizing the number of NGVs in its own
fleet over the next several years to approximately 2,500, and continues to
work with commercial and industrial prospects to assist them in evaluating
NGVs for fleet applications.
Distribution's concentration on public sector initiatives is also yielding
results. Recently, Virginia enacted laws to provide tax credits and
reduced fuel taxes for alternative fuel vehicles (AFV) as well as require
federal Clean Fuel Fleet programs in two areas beyond requirements of
federal law. Pennsylvania established a $3.5 million fund to provide up to
a 60 percent grant for purchases of AFVs and AFV filling equipment.
Pending are initiatives in Kentucky to exempt NGVs from motor fuel testing
and a proposal in Ohio to provide partial sales and use tax exemptions for
the purchase of AFVs and filling equipment.
Distribution continues to actively pursue the developing power generating
market. Distribution currently serves 15 power generation and cogeneration
facilities which consume about 30 Bcf of natural gas each year. CAA-90
offers significant new opportunities to promote the use of natural gas for
electric power generation. Commonwealth Gas Services, Inc. (COS) reached
agreement with Gordonsville Energy Limited Partnership to transport gas for
a new combined cycle generating plant which will produce electric power for
a Virginia utility beginning in mid-1994 which is expected to use
approximately 3.0 Bcf of gas annually. Distribution is currently working
with five additional prospects, both existing and new electric power
generating plants, that may want to use natural gas in order to comply with
the CAA-90 by the year 2000.
39
40
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Distribution's customers operate commercial and industrial cooling and
refrigeration systems with a capacity of approximately four million refrigerant
tons. Less than one percent of this cooling and refrigeration load, roughly
0.2 Bcf, is currently served by gas cooling equipment. Distribution is
aggressively pursuing this market. With improved gas cooling equipment, rising
peak electric costs and concerns about the environmental effects of
chlorofluorocarbon refrigerants, Distribution has an opportunity to add
significant load in the summer months when demand for gas is relatively low.
The GRI estimates that 30-50 percent of this market could be served
economically with gas cooling systems. Sales of gas cooling equipment in
Distribution's service territory increased tenfold in 1993 to 3,096 refrigerant
tons, or about 1.5 percent of total new and replacement equipment sales and 6
percent of large tonnage chiller sales.
Rate Cases
During 1993, Distribution filed two rate cases. COS filed an expedited rate
case for a $3.5 million annual revenue increase, seeking recovery of increased
operating expenses and a return on additional plant investments since COS' 1992
general rate case. A final order in this expedited proceeding is expected by
June 1994.
The Virginia State Corporation Commission (VSCC) in October 1993, issued an
order resolving COS' 1992 general rate case. While the VSCC provided a
favorable increase in annual revenues of $5.6 million, a 4.5 percent increase,
it did not adopt an array of regulatory reform proposals advanced by COS that
included establishing rates based on a fully projected test year and a weather
normalization clause.
In October 1993, the Maryland Public Service Commission approved a rate
settlement for Columbia Gas of Maryland, Inc. (CMD) that provided for a
two-step increase in annual revenues of $2.2 million beginning October 1993,
implementation of a weather normalization adjustment effective with the winter
season which began November 1993, as well as full recovery of postretirement
medical benefit costs.
In contrast to 1993, Distribution's rate activity for 1994 is expected to
accelerate and may involve up to four general rate cases to recover increasing
costs. Columbia Gas of Pennsylvania, Inc. (CPA) filed a rate case in early
1994 and filings are tentatively scheduled in Ohio for the first quarter and in
Virginia and Kentucky on or about May 1. Distribution's total revenue request
could range between $90 and $100 million or roughly 5 percent of its total
revenue. Even though these filings are scheduled early in the year, new rates
will not be effective until the fourth quarter of 1994 or later. All filings
will incorporate the regulatory initiatives currently being pursued by
Distribution and addressed below.
Strategic Regulatory Issues
Distribution continues to actively pursue an array of regulatory reform
initiatives designed to overcome regulatory barriers in the increasingly
competitive Order 636 era. It is advocating a comprehensive package of new
services, increased revenue levels and incentive rate mechanisms. Specific
elements include the use of enhanced projected ratemaking and cost deferral
mechanisms to mitigate adverse timing lags, cost containment and enhanced
customer service and supply initiatives, and revenue stabilization mechanisms
to mitigate the effects of unusual weather conditions and take into account
typical increases in operation and maintenance expenses and capital
expenditures without resorting to time consuming and costly general rate case
proceedings.
While no state commission has yet adopted Distribution's comprehensive reform
package, Distribution has made notable strides in some of its jurisdictions,
including the innovative settlement in Maryland mentioned above reflecting many
elements of its comprehensive initiative. In Ohio, COH has been involved in
proposed legislation that provides utilities the option of filing rate cases on
a fully projected test year basis. In Pennsylvania, CPA is supporting a number
of the Public Utility Commission's (PUC) recently announced initiatives aimed
at providing more regulatory responsiveness and flexibility, specifically,
recognizing in rates construction work in progress for certain investments
placed in service after the ratemaking test year.
40
41
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
FERC Order 636
Distribution successfully began the transition into the new environment created
by Order 636. All of the requirements mandated by the Order have been
implemented by Distribution's interstate pipeline suppliers and thus far
operations have been running smoothly despite the much colder than normal
weather experienced in early 1994. Over the next several years, additional
pipeline filings and related FERC orders, addressing the recovery of pipeline
transition costs stemming from Order 636, are expected. However, based on
current estimates of these transition costs and indications from state
commissions, management does not expect the transition costs to have a
significant adverse impact on Distribution's earnings or customer rates.
Gas Supply
Distribution has developed supply arrangements and operating plans and has
aggregated gas supplies to meet market needs in a flexible, cost- effective
manner. Distribution entered the 1993-94 winter heating season with storage
inventory near maximum levels and with a short-term purchasing/operating plan
designed to fully satisfy firm retail and standby service obligations during
periods that are up to ten percent colder than normal. Early operating
experience during the extreme cold weather conditions of mid-January 1994, when
peak design conditions were met or exceeded over the course of two consecutive
days, thoroughly tested Distribution's capabilities. Throughout this
extraordinary period of record-setting peak demands, Distribution's facilities
maintained deliveries and adequate gas supplies were available. Beyond a few
isolated operating problems and certain brief limitations on customers who
elected to contract for interruptible service, reliable customer service was
maintained.
Environmental Matters
Distribution has initiated a comprehensive environmental program designed to
ensure complete and prompt compliance with all state and federal environmental
requirements. As part of this program, Distribution is continuing the process
of conducting an environmental assessment of its sites and evaluating
procedures. The assessment and evaluation process will continue over the next
three to five years.
Distribution's primary environmental issues relate to former manufactured gas
plant sites. Currently, Distribution has identified twelve former gas plant
sites that it either owned or acquired through facility purchases.
Environmental investigations are being conducted at five of these sites and
remedial action may be required. Investigations will be conducted at a number
of the other sites in the near future. Manufactured gas plant sites currently
being investigated include areas in York and Bellefonte, Pennsylvania, and
Portsmouth, Petersburg and Lynchburg, Virginia. (See Note 12H of Notes to
Consolidated Financial Statements for additional information regarding these
sites.)
To the extent site investigations have been completed, remediation plans
developed and any Distribution responsibility for remedial action established,
the appropriate liability has been recorded. As additional investigations are
completed and remediation costs become probable, the appropriate liability will
be recorded. As of December 31, 1993, the distribution subsidiaries recorded
net liabilities of $5.9 million for environmental matters. Management
anticipates recovery of remediation costs through normal rate proceedings.
SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than
Pensions (OPEB)
Management anticipates that full rate recovery of its accrued OPEB costs in all
states is likely, based on the state commissions' awareness of this issue and
favorable generic policy decisions in a number of jurisdictions coupled with
Distribution's cost management efforts and plans to fully fund all
postretirement benefits allowed in rates in irrevocable trust arrangements.
The present value of the postretirement benefit obligation to be paid to
current and retired employees for all the distribution subsidiaries amounts to
approximately $143.2 million as of December 31, 1993. Of this amount, $138.1
million has been deferred as a regulatory asset pending anticipated recovery
through rates in various jurisdictions.
41
42
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
The Emerging Issues Task Force (EITF) of the Financial Accounting Standards
Board issued guidelines establishing criteria for recording such a regulatory
asset, including a requirement for collection of accrual basis expense in rates
and recovery of the transition obligation within approximately 20 years. These
criteria are not necessarily being adopted by the public utility commissions
regulating the distribution subsidiaries. Differences in requirements between
the accounting rules and the ratemaking decisions ultimately adopted can result
in a writedown of some or all of this regulatory asset. The distribution
subsidiaries have implemented cost containment measures designed to reduce
their OPEB obligations. In addition to other measures, employees will be
required to share a portion of their postretirement health benefit costs and
guidelines have been established redefining years of service requirements
before an employee is eligible for retiree health benefits. Other cost-saving
plans are being reviewed for consideration in an ongoing effort to effectively
manage OPEB costs.
Integrated Resource Planning
Integrated Resource Planning (IRP) combines the concepts of supply side and
demand side management (DSM). The DSM component of IRP generally deals with
programs to reduce customer demand, particularly during peak demand periods,
and thereby reduce the need to construct or acquire additional supply capacity.
The supply side component of IRP generally involves the evaluation of supply
options, including the acquisition of supply from alternative sources or supply
arrangements.
IRP was first implemented for electric utilities by state utility commissions
because of the major investments required to add new electric generating
capacity and the resultant impact of these investments on customer rates.
However, state commissions in Distribution's market area are now actively
considering the adoption of natural gas IRP programs. Distribution generally
regards this as a positive development since it provides a more balanced
competitive situation between gas and electric utilities. Distribution has
significant concerns that electric DSM programs, if not properly controlled by
state regulators, could result in ratepayer-financed marketing programs and
incentives that would inappropriately influence long-term purchases committing
customers to electric use.
The proper development of gas IRP programs should enable Distribution to
continue to compete for new load and replacement appliances and equipment to
improve system load factors and operating economics. However, certain
significant competitive concerns remain because electric utilities can
generally support higher incentives for customers to purchase certain electric
appliances because it is far more expensive to expand electric generating
capacity than to expand gas distribution capacity to deliver the same quantity
of useful energy. Also, most commissions have been reluctant to deal with the
relative environmental impacts of using natural gas versus coal, oil or nuclear
generated electric power for residential and commercial end uses, which would
result in reduced overall emissions and provide higher incentives for gas
usage.
Distribution's IRP efforts are designed to encourage state regulators to deal
with utility IRP programs on a comprehensive basis. Distribution believes that
under such an approach, commissions are more likely to recognize the many
significant advantages of using natural gas rather than electricity for most
residential and commercial and many industrial end uses or at a minimum, work
to maintain more competitive parity between gas and electric rates.
Distribution is working aggressively to communicate the many advantages of a
comprehensive approach to IRP.
Volumes
Throughput for 1993 totaled 509.8 Bcf, a 23.1 Bcf increase over 1992. Higher
transportation deliveries of 13.8 Bcf were due mainly to increased usage by
power generating facilities in Virginia and Pennsylvania. The 9.3 Bcf increase
in tariff sales volumes reflects higher customer usage due primarily to 3
percent colder weather and the net addition of approximately 28,000 customers.
Distribution's throughput for 1992 increased 30.3 Bcf over 1991 after adjusting
for the 1991 sale of a New York subsidiary. Despite 1992 being 2 percent
warmer than normal, it was still 10 percent colder than the prior year.
42
43
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
This colder weather and the net addition of 28,000 new customers led to higher
sales volumes. Transportation volumes also increased in 1992 due largely to
increased deliveries to power-generating facilities as well as other customers
using this service to meet their supply requirements.
Net Revenues
For the year ended December 31, 1993, net revenues of $726 million reflected an
increase of $29.5 million over the same period last year. Increased throughput
generated $18.7 million of this improvement. Additionally, new rates in effect
during 1993 in Virginia and Maryland and the full year impact of rates placed
in effect in 1992 combined to generate $7.6 million with revenues for fixed
charges from new customers accounting for most of the remaining $3.2 million
increase.
Colder weather was the principal reason for 1992's net revenues increasing to
$696.5 million. After adjusting for the sale of the New York subsidiary in
1991, the net revenues in 1992 represented an increase of $62 million over
1991. The full year effect of favorable rate settlements in all of
Distribution's operating areas also contributed to the higher net revenues.
Operating Income
Operating income improved $8.7 million over the previous year. Higher net
revenues of $29.5 million were partially offset by increased operating expenses
of $20.8 million. An $8.8 million increase in operation and maintenance
expense reflecting wage increases, additional personnel requirements associated
with the implementation of Order 636, as well as the filling of certain
vacancies that had been deferred and higher lease costs for the Columbus, Ohio
headquarters building were the primary reasons for the increase. Additionally,
costs for the streamlining of corporate service functions and studies underway
to enhance customer service also contributed to the increase. These increases
were partially offset by a $4.2 million charge recorded in 1992 for COS OPEB
costs. Depreciation expense increased $4.7 million primarily reflecting plant
additions, while increased gross receipts taxes and property taxes of $7.3
million were attributable to higher taxable revenues and plant additions.
After adjusting for the sale of the New York subsidiary, operating income in
1992 of $137.7 million increased $27 million over 1991 as higher net revenues
were partially offset by increased operating expenses. Increased operating
expenses of $558.8 million resulted primarily from higher labor and benefit
costs and the effect of regulatory lag that resulted in only a portion of
increased costs being recovered through rates.
43
44
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM DISTRIBUTION OPERATIONS (UNAUDITED)
Year Ended December 31 (in millions) 1993 1992 1991*
- --------------------------------------------------------------------------------------------------------------
NET REVENUES
Sales revenues $1,754.0 $1,574.2 $1,466.9
Less: Cost of gas sold 1,098.6 945.3 882.2
- ---------------------------------------------------------------------------------------------------------------
Net Sales Revenues 655.4 628.9 584.7
- ---------------------------------------------------------------------------------------------------------------
Transportation revenues 76.7 73.4 66.6
Less: Associated gas costs 6.1 5.8 5.8
- ---------------------------------------------------------------------------------------------------------------
Net Transportation Revenues 70.6 67.6 60.8
- ---------------------------------------------------------------------------------------------------------------
Net Revenues 726.0 696.5 645.5
- ---------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 391.5 382.7 353.9
Depreciation 62.3 57.6 60.5
Other taxes 125.8 118.5 116.2
- ---------------------------------------------------------------------------------------------------------------
Total Operating Expenses 579.6 558.8 530.6
- ---------------------------------------------------------------------------------------------------------------
OPERATING INCOME $ 146.4 $ 137.7 $ 114.9
- ---------------------------------------------------------------------------------------------------------------
* Includes Columbia Gas of New York, Inc. through March 31, 1991.
44
45
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
DISTRIBUTION OPERATING HIGHLIGHTS*
1993 1992 1991 1990 1989
- ---------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES 117.8 99.7 98.0 107.0 119.7
($ in millions)
- ---------------------------------------------------------------------------------------------------------------
THROUGHPUT (Bcf)
Sales
Residential 194.7 186.2 178.4 173.5 201.5
Commercial 83.4 81.8 78.3 76.8 85.0
Industrial 14.0 14.8 10.8 16.6 16.4
Other 0.2 0.2 0.2 0.2 1.1
- ---------------------------------------------------------------------------------------------------------------
Total 292.3 283.0 267.7 267.1 304.0
Transportation 217.5 203.7 194.7 198.6 184.4
- ---------------------------------------------------------------------------------------------------------------
Throughput 509.8 486.7 462.4 465.7 488.4
- ---------------------------------------------------------------------------------------------------------------
SOURCES OF GAS FOR THROUGHPUT
(Bcf)
Sources of Gas Sold
Spot market** 142.3 169.9 113.9 140.6 167.8
Producers 56.9 57.1 64.4 40.4 22.6
Pipelines 118.4 84.0 68.2 51.7 203.9
Storage withdrawals
(injections) (6.7) (10.7) 11.4 38.1 (75.5)
Other (18.6) (17.3) 9.8 (3.7) (14.8)
- ---------------------------------------------------------------------------------------------------------------
Total Sources of Gas Sold 292.3 283.0 267.7 267.1 304.0
Gas received for delivery
to customers 217.5 203.7 194.7 198.6 184.4
- ---------------------------------------------------------------------------------------------------------------
Total Sources 509.8 486.7 462.4 465.7 488.4
- ---------------------------------------------------------------------------------------------------------------
CUSTOMERS
Residential 1,737,609 1,711,946 1,686,918 1,724,281 1,693,914
Commercial 164,037 161,937 160,378 165,144 161,864
Industrial 2,280 2,358 2,342 2,400 2,334
Other 22 24 24 20 26
- ---------------------------------------------------------------------------------------------------------------
Total 1,903,948 1,876,265 1,849,662 1,891,845 1,858,138
- ---------------------------------------------------------------------------------------------------------------
DEGREE DAYS 5,677 5,507 4,998 4,783 5,971
- ---------------------------------------------------------------------------------------------------------------
* Includes Columbia Gas of New York, Inc. through March 31, 1991.
** Reflects volumes under purchase contracts of less than one year.
45
46
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
OTHER ENERGY OPERATIONS
Cogeneration
Independent power production continues to be a growth area for natural gas.
The Corporation is involved in several cogeneration projects through TriStar
Ventures Corporation (TriStar), a wholly-owned subsidiary. Projects in
operation or under construction total nearly 300 megawatts in which TriStar
holds various interests. Three cogeneration facilities are now operating; a
117-megawatt facility in Pedricktown, New Jersey, a 50-megawatt plant in
Binghamton, New York and an 85-megawatt plant in Rumford, Maine. Natural gas
is delivered to the Binghamton and Pedricktown facilities by Columbia
Transmission. These three projects generated $5.8 million and $4.5 million of
income before interest and income taxes in 1993 and 1992, respectively. A
47-megawatt plant near Vineland, New Jersey is scheduled to begin operations in
mid-1994. TriStar and its partners also have other projects in various stages
of development. Value is also generated from the projects for the transmission
subsidiaries of the Corporation who benefit from increased throughput while the
oil and gas segment has increased sales opportunities.
TriStar was participating in the development of a 56-megawatt plant in
Washington, D.C. on which construction had been delayed pending regulatory
review and approval. On October 13, 1993, processing of the building permit
was suspended indefinitely by the District of Columbia. This action combined
with numerous regulatory delays, caused the project to become financially
nonviable. Accordingly, TriStar and its partner halted efforts to build the
project and TriStar wrote off its net investment in the project of $3.1 million
after-tax. On November 1, 1993, the partnership filed an $80 million lawsuit
in federal court against the District of Columbia and certain District
officials.
Propane
During 1993, propane sales by Columbia Propane Corporation and Commonwealth
Propane, Inc., totaled 58.1 million gallons, a decrease of 8 percent from the
previous year. The propane companies serve approximately 68,000 customers in
parts of Maryland, North Carolina, Ohio, Pennsylvania, Virginia and West
Virginia. The companies are focusing their sales efforts on the higher-margin
residential segment.
Coal Operations
The Corporation has in excess of 500 million tons of coal reserves.
Approximately 50 percent of the reserves, much of which contain less than one
percent sulfur, are leased to other parties for development.
Environmental Matters
The Columbia Gas System Service Corporation (Service Corporation) received a
"General Notice of Potential Liability and CERCLA Section 104(2) Request for
Information" concerning a process site to which the Service Corporation sent
certain solvents. This notice was sent to in excess of 100 parties requesting
information about any involvement with the owner of the site or the site
itself. Management has furnished the information requested and does not
believe this Superfund matter will have a material adverse effect on future
income or on the Corporation's financial position.
Net Revenues
Propane sales to wholesale and industrial customers have been decreasing over
the past few years due to unacceptable margins while, to a lesser extent, sales
to higher-margin residential customers have been increasing. As a result of
this strategy, total sales volumes have decreased, but net sales revenues have
been rising. This change led to net sales revenues of $29.8 million in 1993,
an increase of $2.5 million, and in 1992 an increase of $700,000 compared to
the year earlier. Increases in revenues resulting from gas marketing
activities were largely offset by increased products purchased expense.
Revenues in 1993 from services provided to affiliates and coal royalties
resulted in an increase in other revenues of $3.1 million, to $73.4 million,
from the prior year. Other revenues in 1992 of $70.3 million, were $5.2
million
46
47
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
lower than the year earlier primarily because a decrease in revenues from
affiliate companies more than offset higher coal royalty revenues.
Operating Income
The net revenue increase of $5.6 million was more than offset by $10.7 million
higher operating expenses primarily reflecting increased labor and benefits
costs that included employee severance costs recorded in 1993. The 1992 net
revenue decline of $4.5 million compared to 1991 was more than offset by
reduced operating expenses of $6.4 million, resulting from lower labor and
benefits costs in 1992 due to a reduction in the number of employees and a
charge in 1991 for employee severance costs.
STATEMENTS OF OPERATING INCOME FROM OTHER ENERGY OPERATIONS (UNAUDITED)
Year Ended December 31 (in millions) 1993 1992 1991
- ---------------------------------------------------------------------------------------------------------------
NET REVENUES
Sales revenues $233.0 $133.5 $121.0
Less: Products purchased 203.2 106.2 94.4
- ---------------------------------------------------------------------------------------------------------------
Net Sales Revenues 29.8 27.3 26.6
Other revenues 73.4 70.3 75.5
- ---------------------------------------------------------------------------------------------------------------
Net Revenues 103.2 97.6 102.1
- ---------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Operation and maintenance 90.8 80.8 87.6
Depreciation and depletion 5.9 4.9 4.0
Other taxes 4.8 5.1 5.6
- ---------------------------------------------------------------------------------------------------------------
Total Operating Expenses 101.5 90.8 97.2
- ---------------------------------------------------------------------------------------------------------------
OPERATING INCOME $ 1.7 $ 6.8 $ 4.9
- ---------------------------------------------------------------------------------------------------------------
OTHER ENERGY OPERATING HIGHLIGHTS
1993 1992 1991 1990 1989
- ---------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ in millions) 11.2 15.0 10.2 14.1 16.4
- ---------------------------------------------------------------------------------------------------------------
PROPANE
Gallons sold (millions) 58.1 63.3 70.5 74.4 75.2
Customers 67,895 65,899 64,618 63,546 62,707
- ---------------------------------------------------------------------------------------------------------------
47
48
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
CONSOLIDATED REVIEW
Net Income
The Corporation reported net income for 1993 of $152.2 million, or $3.01 per
share, compared to $51.2 million, or $1.01 per share in 1992. After adjusting
for the unusual and bankruptcy related items detailed below, 1993 net income of
$155.1 million was up $56.4 million over the prior year. The oil and gas,
transmission and distribution segments all experienced improved results in
1993. These improvements resulted from increased throughput, the full year
effect of a new rate design implemented by the transmission companies as well
as lower depletion expense, higher prices for gas production and increased oil
and gas production for the oil and gas segment. The distribution segment's
results improved because the weather was 3 percent colder than 1992 and because
of higher transportation volumes.
Unusual and Bankruptcy Related Items
After-tax Effect on Net Income
($ in millions) 1993 1992
- ---------------------------------------------------------------------------------------------------------------
. Estimated interest costs not recorded for prepetition debt 138.1 148.5
. Professional fees and related expenses (25.6) (29.2)
. Interest earned on prepetition obligations 25.9 17.7
. Oil and Gas writedown - (83.4)
. Writedown of the investment in Columbia LNG (37.9) -
. Extraordinary charge - (39.7)
. Proposed IRS settlement (44.3) -
. Environmental accruals (45.0) (40.9)
. Gas inventory charge and WACOG revenues* 26.7 13.1
. Provision for gas supply charges - (24.2)
. Adjustment for FERC order on pipeline direct billings (12.6) -
. Other unusual items (28.2) (9.4)
- ---------------------------------------------------------------------------------------------------------------
Total (2.9) (47.5)
- ---------------------------------------------------------------------------------------------------------------
* Reflects charges that are allowed to be collected by Columbia Transmission to
recover costs when it meets certain competitive tests for its commodity sales
rate or cost of gas.
Operating Income by Segment
The oil and gas segment had operating income of $53.6 million in 1993, compared
to an operating loss of $101.2 million in 1992. The prior period loss was
mainly due to a writedown of $126.4 million in the carrying value of oil and
gas assets due to low energy prices. Lower depletion expense, higher gas
prices and increased oil and gas production also contributed to the current
period increase and were only partially offset by lower oil and liquids prices
and the recording of a reserve for a royalty dispute with the MMS. The average
gas price in 1993 was $2.28 per Mcf, up $0.26 per Mcf over last year, whereas
the average price for oil and liquids decreased to $16.17 per barrel, down
$2.03 per barrel from 1992. Oil and gas production for 1993 of 3,603,000
barrels and 71.5 Bcf, increased 542,000 barrels and 2.3 Bcf, respectively, over
last year.
The transmission segment's 1993 operating income of $178.7 million, up $48.8
million, reflected a significant improvement over the 1992 level. After
adjusting for the pre-tax effect of the unusual items, operating income
increased $37.8 million over 1992. Included in these unusual items are
increased revenues from GIC and WACOG
48
49
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
revenues Columbia Transmission is permitted to recover from its customers when
it met certain competitive tests with other pipelines. These sources of
revenue were unique to Columbia Transmission's merchant function which was
essentially eliminated under Order 636. After adjusting 1992 throughput for a
customer exchange arrangement, throughput improved resulting in higher
revenues. This effect together with the full year effect in 1993 of Columbia
Transmission's new rate design were the principal reasons for the $37.8 million
improvement. Under this new rate design, a greater portion of fixed costs are
collected through a monthly demand charge rather than the commodity charge
where they are susceptible to weather fluctuations. Gas costs continue to be
recovered through commodity charges. Also contributing to the 1993 improvement
over 1992 was approximately $15 million of additional expense recorded in the
prior period for settlements with a supplier.
Weather in the distribution segment's service areas was 3 percent colder than
1992. The colder weather helped raise 1993 operating income to $146.4 million,
an increase of $8.7 million over 1992. Improved recovery of costs through
higher rates in effect in Virginia and Maryland contributed to the increase.
Mitigating these improvements were higher operating expenses that included
increases in labor and benefits expense and costs associated with streamlining
corporate service functions and studies underway to enhance customer service.
Other energy operations had operating income of $1.7 million, a decrease of
$5.1 million compared to 1992. The reduction primarily reflects recording $6.3
million for costs associated with the Service Corporation's reengineering
program.
Revenues
Operating revenues for 1993 of $3,391.2 million, increased more than 16 percent
from the year earlier largely due to the full year effect of Columbia
Transmission's new rate design, pipeline exit fees of $130 million for Columbia
Transmission, higher retail sales resulting from colder weather during 1993 and
higher distribution rates. In addition, Columbia Transmission's WACOG
revenues, sale of storage to customers, higher gas prices and increased oil and
gas production also contributed to the improvement. Revenues associated with
pipeline exit fees were offset in products purchased expense and had no effect
on income.
Operating revenues for 1992 increased $345.2 million over 1991 to $2,922
million due to a combination of higher sales volumes as a result of colder
weather, the full year effect of higher distribution rates and Columbia
Transmission's new rate design and more competitive sales rate.
Expenses
Over the last three years, higher sales necessitated an increase in volumes of
gas purchased resulting in an increase in products purchased expense of $337.6
million in 1993, compared to 1992, and $180.4 million for 1992 over 1991. In
addition, higher average rates for gas purchased, particularly spot market
purchases, also contributed to the increase in 1993. Higher expense for
pipeline exit fees were offset in revenues as mentioned above.
In 1992, Columbia Transmission anticipated only a minimal merchant function
would be offered when Order 636 was implemented in November 1993; therefore, a
provision for gas supply charges of $38.6 million was recorded to reflect a
writedown of certain capitalized gas costs in excess of amounts to be amortized
in 1993.
Higher labor and benefits expense in 1993, which included $14.8 million for
severance costs associated with reengineering many of the System functions to
gain efficiencies and improve competitiveness, together with rising operating
costs led to higher operation and maintenance expense of $26.5 million.
Partially offsetting these increases was higher expense in 1992 for certain
supplier settlements by Columbia Transmission. Raising expense in both 1993
and 1992 were environmental costs of $66.8 million and $65.3 million,
respectively.
The higher environmental costs recorded in 1992 and increased labor and
benefits expense of Columbia Transmission
49
50
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
were the primary reasons for the $111.3 million increase in operation and
maintenance expense over 1991. Additional expenses in 1992 associated with
certain producer settlements also contributed to the increase.
Due to depressed energy prices in early 1992, a writedown was recorded of
$126.4 million in the carrying value of oil and gas properties. This was the
principal reason for the $128.3 million decrease in 1993 in depreciation and
depletion expense. The significant increase in depreciation and depletion
expense of $83.1 million in 1992 over 1991 was also the result of this
writedown, which was partially offset by writedowns for the Canadian oil and
gas properties in 1991.
Income Taxes
As detailed in Note 5 of Notes to Consolidated Financial Statements, income
taxes in 1993 increased $65.4 million over last year reflecting increased
income, adjustments due to the IRS settlement and the increased tax rate. In
1992, income taxes increased $481.5 million as the Corporation had pre-tax book
income in 1992 compared to a loss in 1991.
Other Income (Deductions)
Other Income (Deductions) reduced income in 1993 and 1992 by $85.3 million and
$1.5 million, respectively. In 1993, interest expense increased $87.8 million
due largely to recording interest on prior years' taxes of $74.5 million
primarily as a result of the IRS settlement. Interest income and other, net
decreased $13.2 million primarily reflecting $19.5 million for a FERC order
eliminating interest payments from certain upstream pipeline suppliers and a
reserve for pipeline partnership investments partially offset by increased
interest income on prior years' taxes and other issues. Income was improved in
1993 and 1992 by approximately $212.4 million and $224.9 million, respectively,
from not accruing interest expense for prepetition obligations. (Since the
July 31, 1991 bankruptcy filing, the estimated effect of not accruing interest
expense on these prepetition obligations totals approximately $523 million.
However, the actual interest that will ultimately be paid pursuant to the final
plans of reorganization could differ significantly and cannot be determined at
this time.) Reorganization items, net reflects bankruptcy issues that improved
income $8.9 million in 1993 compared to an income decrease of $8.3 million last
year. Included in these amounts is $39.9 million of interest earned on
accumulated cash, up $13 million over 1992, and $31 million for 1993
professional fees and related expenses together with other miscellaneous
reorganization items, a decrease of $4.2 million from last year.
In 1992 Other Income (Deductions), net reduced income $1.5 million versus
$119.4 million in 1991. Income was improved in both 1992 and 1991 by not
accruing interest expense on prepetition obligations by approximately $224.9
million and $85.6 million, respectively. The decrease of $11.9 million in
Interest Income and Other, net was due to several items including a $17.9
million gain in 1991 on the sale of the New York distribution subsidiary and a
$2.9 million gain on the 1991 sale of the Canadian oil and gas properties.
These items were partially offset by a $14.5 million writedown for certain
cogeneration projects. The change between 1992 and 1991 for bankruptcy issues
increased income $6.1 million. Professional fees and related expenses,
combined with other miscellaneous reorganization items, were $35.2 million and
$18.9 million in 1992 and 1991, respectively, while interest earned on
accumulated cash was $26.9 million in 1992 and $4.5 million in the prior year.
50
51
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
STATEMENTS OF COMMON STOCK PRICES AND DIVIDENDS
Market Price
----------------------------------------------------------- Quarterly
Quarter Ended High Low Close Dividends Paid
- ---------------------------------------------------------------------------------------------------------------
$ $ $ c.
1993
December 31 27 3/8 22 1/4 22 3/8 -
September 30 27 1/2 20 26 1/8 -
June 30 25 3/4 20 24 3/4 -
March 31 24 1/4 18 1/8 22 1/4 -
- ---------------------------------------------------------------------------------------------------------------
1992
December 31 23 7/8 18 5/8 19 1/8 -
September 30 20 16 3/8 20 -
June 30 17 5/8 14 17 -
March 31 19 1/4 16 1/8 17 3/4 -
- ---------------------------------------------------------------------------------------------------------------
LIQUIDITY AND CAPITAL RESOURCES
Cash from Operations
The full year effect of Transmission's new rate design, higher rates for
Distribution and colder weather during 1993 compared to last year, together
with certain refunds received from suppliers, resulted in net cash from
operations of $850.4 million, an increase of $85 million for 1993. Higher oil
and gas production and increased gas prices also contributed to this
improvement. Cash received from customers increased $412 million in 1993,
primarily reflecting increased volumes due to colder weather earlier in the
year together with higher rates. The receipt of rate refunds by certain
subsidiaries led to the $79.4 million rise in other operating cash receipts.
An increase in the spot market price for gas and additional gas volumes
purchased to meet customer requirements resulted in $302.2 million more cash
being paid to suppliers partially offsetting the above cash improvements. In
addition, a refund payment by Columbia Transmission led to a $102 million rise
in other operating cash payments in 1993.
Colder weather in 1992 compared to the prior year and the suspension of
interest payments on August 1, 1991, due to the bankruptcy filing raised net
cash from operations $233.8 million to $765.4 million in 1992 over 1991.
Higher 1992 throughput from colder weather, increased receipts due to
implementing a new rate design for Columbia Transmission and higher
distribution rates were the primary reasons for the $300.5 million increase in
cash received from customers. The suspension of interest payments on
prepetition debt obligations led to the $100.4 million decrease in interest
paid. Partially offsetting these improvements was the 1991 receipt of a
settlement payment on a property dispute which caused other operating cash
receipts to decline $48 million. Also, higher income taxes due to timing
differences between periods and increased property tax assessments caused
income taxes paid and other tax payments to increase $40.6 million and $31.5
million, respectively.
The Corporation maintains a debtor-in-possession facility (DIP Facility) for up
to $100 million, including the availability of letters of credit of up to $50
million. The DIP Facility is available for use in conjunction with internally
generated funds for general corporate purposes and to provide financing for
subsidiaries not involved in the bankruptcy proceedings. As of January 31,
1994, $12.7 million of letters of credit were outstanding under the
51
52
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
ESULTS OF OPERATIONS (Continued)
DIP Facility. The DIP Facility expires December 31, 1994, although a request
to extend it will be made, if necessary. During 1993, there were no borrowings
under the DIP Facility. Absent unusual circumstances, the Corporation expects
to remain in a cash surplus position during all of 1994. As of January 31,
1994, the Corporation and its subsidiaries, excluding Columbia Transmission,
had excess cash of $148 million, which was invested in money market
instruments.
The liquidity needs of Columbia Transmission are being satisfied by internally
generated funds. As of January 31, 1994, Columbia Transmission had $1,250.9
million invested in money market instruments through a wholly-owned subsidiary,
Columbia Transmission Investment Corporation. Columbia Transmission also
maintains a DIP Facility solely for the issuance of letters of credit for up to
$25 million. As of January 31, 1994, the balance of outstanding letters of
credit under Columbia Transmission's DIP Facility was $1.8 million. In
December 1993, Columbia Transmission extended its DIP Facility through December
31, 1995.
The Corporation's subsidiaries (other than Columbia Transmission during
bankruptcy) must receive SEC approval under the Public Utility Holding Company
Act of 1935 for all financing. As part of the approval process, the
Corporation files the financing requirements of each of its subsidiaries with
the SEC along with other material supporting management's opinion that the
amounts requested are in the best interest of the Corporation's investors. In
connection with recent filings, the Corporation has been requested to provide
greater detail in support of the financing of subsidiaries which have, from
time to time, experienced losses. These companies include: Columbia LNG,
TriStar, TriStar Capital Corporation, Columbia Coal Gasification Corporation
and Columbia Development. The need to provide information requested by the SEC
to satisfy these concerns has made the receipt of timely approval more
difficult and future delays could be experienced. However, management
continues to believe it will receive approval of its financing requests.
CAPITAL EXPENDITURES
(in millions) 1994 1993 1992
- ----------------------------------------------------------------------------------------
Columbia Transmission $162 $121 $106
Other Transmission 39 16 8
Distribution 152 118 100
Oil and Gas 91 95 71
Other Energy 24 11 15
- ----------------------------------------------------------------------------------------
Total $468 $361 $300
- ----------------------------------------------------------------------------------------
Capital expenditures for 1993 were $361 million, an increase of $61 million
over 1992. The increase reflects expenditures on some projects that had been
deferred in previous years. In 1992 and 1991, the Corporation's subsidiaries
reduced capital expenditures to the extent possible consistent with the need to
maintain safe and efficient operating facilities, the need to meet new service
and tariff obligations, drilling commitments and the need to preserve going
concern values.
Some of the Corporation's subsidiaries will be initiating projects that can no
longer be deferred which will increase the 1994 program $107 million, to $468
million.
In 1994, Distribution will make investments of approximately $18 million to
improve the efficiency of support services where expenditures had previously
been deferred. Also included in Distribution's 1994 capital expenditure
program are expenditures to provide deliveries to gas powered electric
generating plants in its market areas and third-party natural gas vehicle
public refueling stations. The majority of the transmission companies'
expenditures will be for maintaining their extensive pipeline and storage
system. In addition, $26 million is included for a project to provide gas to a
New England electric generating facility which has been deferred since 1990
pending regulatory approval. Expenditures in 1994 for the oil and gas segment
will remain essentially at 1993 levels. The current weakness in oil prices has
resulted in a reduction in planned 1994 expenditures for exploratory drilling.
The majority of the segment's expenditures will be for less risky development
drilling.
52
53
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- ----------------------------------------------------------------------------------------------------------
Index Page
- ----------------------------------------------------------------------------------------------------------
Comparative Gas Operations Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
Report of Independent Public Accountants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
Statements of Consolidated Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
Statements of Consolidated Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
Statements of Consolidated Common Stock Equity . . . . . . . . . . . . . . . . . . . . . . . . . . 60
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
Schedule I - Marketable Securities - Other Investments . . . . . . . . . . . . . . . . . . . . . . 100
Schedule V - Property, Plant and Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102
Schedule VI - Accumulated Depreciation and Depletion of Property,
Plant and Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105
Schedule VIII - Valuation and Qualifying Accounts . . . . . . . . . . . . . . . . . . . . . . . . . 108
Schedule IX - Short-Term Borrowings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109
Schedule X - Supplementary Income Statement Information . . . . . . . . . . . . . . . . . . . . . . 111
- ----------------------------------------------------------------------------------------------------------
53
54
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
COMPARATIVE GAS OPERATIONS DATA
The Columbia Gas System, Inc. and Subsidiaries
1993 1992 1991 1990 1989
- ---------------------------------------------------------------------------------------------------------------
SALES AND TRANSPORTATION
REVENUES ($ in millions)*
Residential 1,217.5 1,089.1 1,019.3 943.9 1,140.6
Commercial 466.5 426.5 402.4 370.2 450.7
Industrial 153.8 97.6 78.0 94.1 99.2
Wholesale 683.1 617.6 407.1 341.5 846.7
Other 45.2 51.5 48.1 51.5 53.1
Transportation 601.9 438.6 425.0 373.2 512.3
- ---------------------------------------------------------------------------------------------------------------
Total Sales and Transportation Revenues 3,168.0 2,720.9 2,379.9 2,174.4 3,102.6
- ---------------------------------------------------------------------------------------------------------------
SALES (Bcf)*
Residential 194.8 186.3 178.5 173.5 201.5
Commercial 83.5 81.9 78.4 76.8 85.0
Industrial 53.8 29.4 24.9 31.2 25.7
Wholesale 167.3 171.3 111.5 92.1 252.9
Other 25.3 30.6 33.7 28.3 31.1
- ---------------------------------------------------------------------------------------------------------------
Total Sales 524.7 499.5 427.0 401.9 596.2
Transportation volumes 993.7 982.4 972.1 977.6 980.5
- ---------------------------------------------------------------------------------------------------------------
Total Throughput 1,518.4 1,481.9 1,399.1 1,379.5 1,576.7
- ---------------------------------------------------------------------------------------------------------------
SOURCES OF GAS SOLD (Bcf)
Total gas purchased 476.3 433.0 370.6 453.3 449.4
Total gas produced 71.5 69.2 76.3 75.3 77.9
Exchange gas - net (11.2) 17.5 (15.3) 21.1 (15.0)
Gas withdrawn from (delivered to) storage 17.9 14.5 24.7 (137.5) 109.0
Company use and other (29.8) (34.7) (29.3) (10.3) (25.1)
- ---------------------------------------------------------------------------------------------------------------
Total Sources of Gas Sold 524.7 499.5 427.0 401.9 596.2
- ---------------------------------------------------------------------------------------------------------------
CUSTOMERS AT YEAR END
Residential 1,737,609 1,711,946 1,687,631 1,724,281 1,693,914
Commercial 164,037 161,937 160,420 165,144 161,864
Industrial 2,280 2,358 2,345 2,400 2,334
Wholesale 5 78 80 81 78
Other 143 217 200 142 127
- ---------------------------------------------------------------------------------------------------------------
Total Customers at Year End 1,904,074 1,876,536 1,850,676 1,892,048 1,858,317
- ---------------------------------------------------------------------------------------------------------------
AVERAGE USAGE PER CUSTOMER (Mcf)
Residential 112.1 108.8 105.8 100.6 119.0
Commercial 509.0 505.8 488.7 465.0 525.1
- ---------------------------------------------------------------------------------------------------------------
DEGREE DAYS FOR RETAIL OPERATIONS 5,677 5,507 4,998 4,783 5,971
% Colder (warmer) than normal 1 (2) (11) (15) 7
- ---------------------------------------------------------------------------------------------------------------
* Certain amounts in prior periods have been reclassified to conform with the
current presentation.
54
55
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of The Columbia Gas System, Inc.:
We have audited the accompanying consolidated balance sheets of The Columbia
Gas System, Inc. (a Delaware corporation, the "Corporation") and subsidiaries
as of December 31, 1993 and 1992, and the related statements of consolidated
income, cash flows and common stock equity for each of the three years in the
period ended December 31, 1993. These financial statements are the
responsibility of the Corporation's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of the Corporation and
subsidiaries as of December 31, 1993 and 1992, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1993, in conformity with generally accepted accounting principles.
On July 31, 1991, the Corporation and Columbia Gas Transmission Corporation
("Columbia Transmission"), a wholly-owned subsidiary, filed separate petitions
seeking protection under Chapter 11 of the Federal Bankruptcy Code. Note 2
discusses, among other matters, uncertainties associated with the Chapter 11
proceedings, including the status of the Corporation's loans to Columbia
Transmission, certain prepetition intercompany asset transfers and the
measurement of certain liabilities. This note also discusses purported class
action and other complaints which have been filed against the Corporation
generally alleging violations of certain securities laws. The accompanying
financial statements do not reflect any liability associated with these
complaints as the Corporation believes it has meritorious defenses to these
actions; however, the ultimate outcome is uncertain. As a result of these
matters, the Corporation may take, or be required to take, actions which may
cause assets to be realized or liabilities to be liquidated for amounts other
than those reflected in the financial statements. These factors create
substantial doubt about the Corporation's ability to continue as a going
concern. The accompanying financial statements have been prepared assuming
that the Corporation and Columbia Transmission will continue as going concerns
which contemplates the realization of assets and payment of liabilities in the
ordinary course of business. The appropriateness of the Corporation continuing
to present financial statements on a going concern basis is dependent upon,
among other items, the terms of the ultimate plan of reorganization and the
ability to generate sufficient cash from operations and financing sources to
meet obligations.
As discussed in Note 4, effective January 1, 1991, the Corporation changed its
method of accounting for income taxes and postretirement benefits other than
pensions pursuant to standards promulgated by the Financial Accounting
Standards Board.
The schedules listed in the Index to Item 8, Financial Statements and
Supplementary Data, are the responsibility of the Corporation's management and
are presented for purposes of complying with the Securities and Exchange
Commission's rules and are not part of the basic consolidated financial
statements. These schedules have been subjected to the auditing procedures
applied in the audits of the basic consolidated financial statements and, in
our opinion, fairly state in all material respects the financial data required
to be set forth therein in relation to the basic consolidated financial
statements taken as a whole.
ARTHUR ANDERSEN & CO.
New York, New York
February 10, 1994
55
56
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED INCOME
The Columbia Gas System, Inc. and Subsidiaries
Year Ended December 31 (in millions except per share amounts) 1993* 1992* 1991*
- ---------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Gas sales $2,566.1 $2,282.3 $1,954.9
Transportation 601.9 438.6 425.0
Other 223.2 201.1 196.9
- ---------------------------------------------------------------------------------------------------------------
Total Operating Revenues 3,391.2 2,922.0 2,576.8
- ---------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Products purchased 1,574.5 1,236.9 1,056.5
Provision for gas supply charges - 38.6 1,319.2
Operation 782.5 764.4 689.4
Maintenance 165.5 157.1 120.8
Depreciation and depletion 239.8 368.1 285.0
Other taxes 198.0 194.0 192.3
Writedown of investment in Columbia LNG Corporation 57.5 - -
- ---------------------------------------------------------------------------------------------------------------
Total Operating Expenses 3,017.8 2,759.1 3,663.2
- ---------------------------------------------------------------------------------------------------------------
OPERATING INCOME (LOSS) 373.4 162.9 (1,086.4)
- ---------------------------------------------------------------------------------------------------------------
OTHER INCOME (DEDUCTIONS)
Interest income and other, net (Note 13) 7.3 20.5 32.4
Interest expense and related charges** (Note 14) (101.5) (13.7) (137.4)
Reorganization items, net (Note 2) 8.9 (8.3) (14.4)
- ---------------------------------------------------------------------------------------------------------------
Total Other Income (Deductions) (85.3) (1.5) (119.4)
- ---------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE INCOME TAXES, EXTRAORDINARY
ITEM AND CUMULATIVE EFFECT OF ACCOUNTING CHANGES 288.1 161.4 (1,205.8)
Income taxes (Note 5) 135.9 70.5 (411.0)
- ---------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGES 152.2 90.9 (794.8)
Extraordinary item (Note 12F) - (39.7) -
Cumulative effect of change in accounting
for income taxes (Note 4B) - - 170.0
Cumulative effect of change in accounting
for postretirement benefits (Note 4A) - - (69.6)
- ---------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) $ 152.2 $ 51.2 $ (694.4)
- ---------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------
EARNINGS (LOSS) PER SHARE OF COMMON STOCK
(based on average shares outstanding)
Before extraordinary item and accounting changes $ 3.01 $ 1.79 $ (15.72)
Extraordinary item - (0.78) -
Change in accounting for income taxes - - 3.36
Change in accounting for postretirement benefits - - (1.38)
- ---------------------------------------------------------------------------------------------------------------
Earnings (Loss) on Common Stock $ 3.01 $ 1.01 $ (13.74)
- ---------------------------------------------------------------------------------------------------------------
DIVIDENDS PER SHARE OF COMMON STOCK - - $ 1.16
- ---------------------------------------------------------------------------------------------------------------
AVERAGE COMMON SHARES OUTSTANDING (thousands) 50,559 50,559 50,537
- ---------------------------------------------------------------------------------------------------------------
*Reference is made to Notes 1A and 2 of Notes to Consolidated Financial
Statements.
**Due to the bankruptcy filings, interest expense of approximately $212
million, $225 million and $86 million has not been recorded for 1993, 1992
and 1991, respectively.
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
56
57
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
CONSOLIDATED BALANCE SHEETS
The Columbia Gas System, Inc. and Subsidiaries
ASSETS as of December 31 (in millions) 1993* 1992*
- ---------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Gas utility and other plant, at original cost $6,329.8 $6,115.7
Accumulated depreciation and depletion (3,048.4) (2,927.4)
- ---------------------------------------------------------------------------------------------------------------
3,281.4 3,188.3
- ---------------------------------------------------------------------------------------------------------------
Oil and gas producing properties, full cost method 1,208.7 1,190.4
Accumulated depletion (600.0) (602.1)
- ---------------------------------------------------------------------------------------------------------------
Net Property, Plant and Equipment 3,890.1 3,776.6
- ---------------------------------------------------------------------------------------------------------------
INVESTMENTS AND OTHER ASSETS
Accounts receivable - noncurrent 218.9 218.0
Unconsolidated affiliates 67.7 66.7
Investment in Columbia LNG Corporation 10.1 51.9
Gas supply prepayments 0.6 20.0
Other 27.9 31.2
- ---------------------------------------------------------------------------------------------------------------
Total Investments and Other Assets 325.2 387.8
- ---------------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and temporary cash investments 1,340.4 820.6
Accounts receivable
Customers (less allowance for doubtful accounts
of $11.8 and $11.8, respectively) 588.7 490.1
Other 132.7 231.4
Gas inventory 197.8 330.7
Other inventories - at average cost 40.1 47.4
Prepayments 124.6 127.0
Other 63.0 56.8
- ---------------------------------------------------------------------------------------------------------------
Total Current Assets 2,487.3 2,104.0
- ---------------------------------------------------------------------------------------------------------------
DEFERRED CHARGES 255.3 237.5
- ---------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $6,957.9 $6,505.9
- ---------------------------------------------------------------------------------------------------------------
*Reference is made to Notes 1A and 2 of Notes to Consolidated Financial
Statements.
**The Corporation has 10,000,000 shares of preferred stock, $50 par value,
authorized but unissued.
***Due to the bankruptcy filings, accrued interest of approximately
$523 million and $311 million has not been recorded as of December 31, 1993
and December 31, 1992, respectively.
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
57
58
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
CAPITALIZATION AND LIABILITIES as of December 31 (in millions) 1993* 1992*
- ---------------------------------------------------------------------------------------------------------------
COMMON STOCK EQUITY
Common stock, par value $10 per share - outstanding
50,559,225 shares $505.6 $ 505.6
Additional paid in capital 601.8 601.8
Retained earnings 189.9 37.7
Unearned employee compensation (Note 9) (70.0) (70.0)
- ---------------------------------------------------------------------------------------------------------------
Total Common Stock Equity 1,227.3 1,075.1
LONG-TERM DEBT 4.8 5.4
- ---------------------------------------------------------------------------------------------------------------
Total Capitalization** 1,232.1 1,080.5
- ---------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Debt obligations 1.3 1.4
Accounts and drafts payable 184.4 231.7
Accrued taxes 129.5 144.1
Estimated rate refunds 277.8 182.3
Estimated supplier obligations 146.3 0.4
Transportation and exchange gas payable 66.8 54.8
Deferred income taxes - 19.7
Other*** 287.7 203.2
- ---------------------------------------------------------------------------------------------------------------
Total Current Liabilities 1,093.8 837.6
- ---------------------------------------------------------------------------------------------------------------
LIABILITIES SUBJECT TO CHAPTER 11 PROCEEDINGS (Note 2) 3,927.8 3,967.2
- ---------------------------------------------------------------------------------------------------------------
OTHER LIABILITIES AND DEFERRED CREDITS
Deferred income taxes - noncurrent 253.8 190.3
Investment tax credits 40.0 40.8
Postretirement benefits other than pensions 230.0 233.4
Other 180.4 156.1
- ---------------------------------------------------------------------------------------------------------------
Total Other Liabilities and Deferred Credits 704.2 620.6
- ---------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 2, 3, 4, 9 and 12) - -
- ---------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES $6,957.9 $6,505.9
- ---------------------------------------------------------------------------------------------------------------
58
59
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED CASH FLOWS
The Columbia Gas System, Inc. and Subsidiaries
Year Ended December 31 (in millions) 1993* 1992* 1991*
- -------------------------------------------------------------------------------------------------------------
OPERATIONS
Cash received from customers $3,292.1 $2,880.1 $2,579.6
Other operating cash receipts 205.0 125.6 173.6
Cash paid to suppliers (1,329.5) (1,027.3) (1,012.1)
Interest paid (0.5) (1.4) (101.8)
Income taxes paid (88.7) (120.4) (79.8)
Other tax payments (209.0) (196.0) (164.5)
Cash paid to employees and for
other employee benefits (515.0) (479.1) (464.2)
Other operating cash payments (509.0) (407.0) (396.0)
Reorganization items - net 5.0 (9.1) (3.2)
- ---------------------------------------------------------------------------------------------------------------
Net Cash From Operations 850.4 765.4 531.6
- ---------------------------------------------------------------------------------------------------------------
INVESTMENT ACTIVITIES
Capital expenditures** (345.7) (294.5) (376.5)
Gas supply prepayments - net (0.4) 3.2 (36.3)
Other investments - net 4.3 72.2 89.3
- ---------------------------------------------------------------------------------------------------------------
Net Investment Activities (341.8) (219.1) (323.5)
- ---------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Dividends paid - - (55.7)
Issuance of revolving credit agreement - - 20.0
Retirement of long-term debt and preferred stock (0.8) (2.4) (20.3)
Issuance of common stock - - 3.4
Increase in short-term debt and other
financing activities 12.0 4.4 108.9
Net debtor-in-possession financing - (136.0) 136.0
- ---------------------------------------------------------------------------------------------------------------
Net Financing Activities 11.2 (134.0) 192.3
- ---------------------------------------------------------------------------------------------------------------
Increase in cash and temporary cash
investments 519.8 412.3 400.4
Cash and temporary cash investments
at beginning of year 820.6 408.3 7.9
- ---------------------------------------------------------------------------------------------------------------
Cash and temporary cash investments
at end of year*** $ 1,340.4 $ 820.6 $ 408.3
- ---------------------------------------------------------------------------------------------------------------
NET INCOME RECONCILIATION:
Net income (loss) $ 152.2 $ 51.2 $ (694.4)
Items not requiring (providing) cash:
Depreciation and depletion 239.8 368.1 285.0
Deferred income taxes 19.1 (30.3) (525.7)
Amortization of prepayments for producer
contract modifications 19.3 23.9 54.5
Provision for gas supply charges - 38.6 1,319.2
Extraordinary item - 39.7 -
Change in accounting for income taxes - - (170.0)
Change in accounting for postretirement benefits - - 69.6
Gain on sale of interests in subsidiaries - - (21.4)
Other - net 191.9 182.7 39.6
Net change in working capital (Note 15) 228.1 91.5 175.2
- ---------------------------------------------------------------------------------------------------------------
NET CASH FROM OPERATIONS $ 850.4 $ 765.4 $ 531.6
- ---------------------------------------------------------------------------------------------------------------
*Reference is made to Notes 1A and 2 of Notes to Consolidated Financial
Statements.
**Includes amounts transferred from interest paid, cash paid to employees and
for other employee benefits and other operating cash payments.
***The Corporation considers all highly liquid debt instruments purchased with a
maturity of three months or less to be cash equivalents.
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
59
60
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY
The Columbia Gas System, Inc. and Subsidiaries
Accumulated
Common Stock* Foreign
--------------------------- Additional Unearned Currency
(In millions except for Shares Par Paid In Retained Employee Translation
share amounts) Outstanding(000) Value Capital Earnings Compensation Adjustment
- ---------------------------------------------------------------------------------------------------------------
Balance at December 31, 1990 50,472 $ 504.7 $ 599.2 $ 738.3 $ (89.5) $ 5.1
Net Loss (694.4)
Common stock dividends
($1.16 per share) (Note 2) (58.6)
Common stock issued:
Dividend Reinvestment Plan 75 0.8 2.4
Long-Term Incentive Plan 12 0.1 0.4
Other (0.2) 1.2 2.5 (5.1) **
- ---------------------------------------------------------------------------------------------------------------
Balance at December 31, 1991 50,559 505.6 601.8 (13.5) (87.0) -
Net Income 51.2
Sale of LESOP shares 17.0
- ---------------------------------------------------------------------------------------------------------------
Balance at December 31, 1992 50,559 505.6 601.8 37.7 (70.0) -
Net Income 152.2
- ---------------------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1993 50,559 $505.6 $601.8 $ 189.9 $ (70.0) $ -
- ---------------------------------------------------------------------------------------------------------------
*100 million shares authorized at December 31, 1993, 1992 and 1991 - $10 par
value.
**The Corporation's only foreign subsidiary, Columbia Gas Development of
Canada Ltd., was sold during 1991.
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
60
61
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. PRINCIPLES OF CONSOLIDATION. The Consolidated Financial Statements
include the accounts of the Corporation and all subsidiaries. All
intercompany accounts and transactions have been eliminated, except
for the Corporation's investment in Columbia LNG Corporation (see Note
12F).
On July 31, 1991, the Corporation and its wholly-owned subsidiary,
Columbia Gas Transmission Corporation (Columbia Transmission), filed
separate petitions seeking protection under Chapter 11 of the Federal
Bankruptcy Code. The debtor companies are operating their businesses
as debtors-in-possession (DIP) under the jurisdiction of the United
States Bankruptcy Court for the District of Delaware (Bankruptcy
Court). As such, the debtor companies cannot engage in transactions
considered to be outside the ordinary course of business without
obtaining Bankruptcy Court approval (see Note 2).
The accompanying financial statements reflect all adjustments
necessary in the opinion of management to present fairly the results
of operations in accordance with generally accepted accounting
principles applicable to a going concern. Such presentation
contemplates the realization of assets and payment of liabilities in
the ordinary course of business. As a result of the reorganization
proceedings under Chapter 11, the debtor companies may take, or be
required to take, actions which may cause assets to be realized, or
liabilities to be liquidated, for amounts other than those reflected
in the financial statements. The appropriateness of continuing to
present consolidated financial statements on a going concern basis is
dependent upon, among other things, the terms of the ultimate plan of
reorganization, future profitable operations, the ability to comply
with DIP and other financing agreements and the ability to generate
sufficient cash from operations and financing sources to meet
obligations. The consolidated financial statements do not include any
adjustments relating to the recoverability and classification of
recorded asset amounts, or the amounts and classification of
liabilities that might be necessary as a result of the outcome of the
uncertainties discussed herein.
Certain reclassifications have been made to the 1992 and 1991
financial statements to conform to the 1993 presentation.
B. BASIS OF ACCOUNTING FOR RATE-REGULATED SUBSIDIARIES. Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effects of Certain Types of Regulation," provides that rate-regulated
public utilities account for and report assets and liabilities
consistent with the economic effect of the way in which regulators
establish rates, if the rates established are designed to recover the
costs of providing the regulated service and if the competitive
environment makes it reasonable to assume that such rates can be
charged and collected. The Corporation's interstate transmission
companies did not meet these criteria, and consequently are not
applying the provisions of SFAS No. 71. In 1992, management concluded
that it was no longer appropriate for Columbia LNG Corporation
(Columbia LNG) to continue application of SFAS No. 71 (see Note 12F).
The Corporation's gas distribution subsidiaries follow the accounting
and reporting requirements of SFAS No. 71.
C. GAS UTILITY AND OTHER PLANT AND RELATED DEPRECIATION. Property, plant
and equipment (principally utility plant) are stated at original cost.
The cost of gas utility and other plant of the distribution companies
includes an allowance for funds used during construction (AFUDC).
In addition, Columbia Gas of Ohio, Inc. is permitted to include in its
plant investment post-in-service carrying charges on those eligible
plant investments which are placed in service between December 31,
1990, and December 31, 1994. Subject to commission approval, the
carrying charges are also authorized
61
62
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
to be included in base rates in subsequent rate filings. These
carrying charges are subject to a net income limitation, as
determined by the commission. Property, plant and equipment of other
subsidiaries includes interest during construction (IDC).
The 1993, 1992 and 1991 before-tax rates for AFUDC and IDC were 8.0
percent and 9.6 percent, respectively. They represent the rates in
effect prior to Chapter 11 filings. The portion of interest
capitalized by subsidiaries during the period the Corporation is in
bankruptcy is eliminated in the Consolidated Financial Statements.
Improvements and replacements of retirement units are capitalized at
cost. When units of property are retired, the accumulated provision
for depreciation is charged with the cost of the units and the cost of
removal, net of salvage. Maintenance, repairs and minor replacements
of property are charged to expense. The Corporation's subsidiaries
provide for annual depreciation on a composite straight-line basis.
The average annual depreciation rate for Transmission property was 2.6
percent in 1993, 1992 and 1991. The average annual depreciation rate
for Distribution property was 3.3 percent in 1993 and 1992, and 3.6
percent in 1991.
D. OIL AND GAS PRODUCING PROPERTIES. The Corporation's subsidiaries
engaged in exploring for and developing oil and gas reserves follow
the full cost method of accounting. Under this method of accounting,
all productive and nonproductive costs directly identified with
acquisition, exploration and development activities are capitalized in
a countrywide cost center. If costs exceed the sum of the estimated
present value of the cost center's net future oil and gas revenues and
the lower of cost or estimated value of unproved properties, an amount
equivalent to the excess is charged to current depletion expense.
Gains or losses on the sale or other disposition of oil and gas
properties are normally recorded as adjustments to capitalized costs.
Depletion for domestic subsidiaries is based upon the ratio of
current-year revenues to expected total revenues, utilizing current
prices, over the life of production. Depletion for the Canadian
subsidiary, which was sold as of December 31, 1991, was based upon
the ratio of volumes produced to total reserves.
E. COMMODITY HEDGING. Commodity futures, options on futures, and
commodity price swaps are used from time to time to hedge prices of
crude oil, natural gas production, propane inventories and commitments
for natural gas purchases and sales, in order to minimize the risk of
market fluctuations. Under internal guidelines, hedging positions
for oil and gas production can be taken for up to 80 percent of the
expected uncommitted monthly production. Gains and losses on the
hedging transactions are recognized when the hedged commodity is sold
or purchased.
F. GAS INVENTORY. Gas inventory is carried at cost on a last-in,
first-out (LIFO) basis. The estimated replacement cost of gas
inventory in excess of carrying amounts at December 31, 1993, was
approximately $85 million for the distribution companies.
Liquidation of LIFO layers related to gas delivered by the distribu-
tion companies does not affect income since the effect is passed
through to customers as part of purchased gas adjustment tariffs.
As a result of implementing Federal Energy Regulatory Commission
(FERC) Order No. 636 (Order 636), Columbia Transmission substantially
eliminated its merchant function and, therefore, no longer carries a
gas inventory. Amounts previously recorded as "Gas Inventory -
Noncurrent" have been reclassified to Property, Plant and Equipment
which represents the volume of gas required to maintain pressure
levels for storage service.
G. INCOME TAXES AND INVESTMENT TAX CREDITS. The Corporation and its
subsidiaries record income taxes to recognize full interperiod tax
allocations. Under the liability method, deferred income taxes are
62
63
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
recognized for the tax consequences of temporary differences by
applying enacted statutory tax rates applicable to future years to
differences between the financial statement carrying amounts and the
tax basis of existing assets and liabilities.
Previously recorded investment tax credits of the gas distribution
subsidiaries were deferred and are being amortized over the life of
the related properties to conform with regulatory policy.
H. ESTIMATED RATE REFUNDS. Certain rate-regulated subsidiaries collect
revenues subject to refund pending final determination in rate
proceedings. In connection with such revenues, estimated rate refund
liabilities are recorded which reflect management's current judgment
of the ultimate outcome of the proceedings. No provisions are made
when, in the opinion of management, the facts and circumstances
preclude a reasonable estimate of the outcome.
I. DEFERRED GAS PURCHASE COSTS. The Corporation's gas distribution
subsidiaries defer differences between gas purchase costs and the
recovery of such costs in revenues, and adjust future billings for
such deferrals on a basis consistent with applicable tariff
provisions.
J. REVENUE RECOGNITION. The Corporation's rate-regulated subsidiaries
bill customers on a monthly cycle billing basis. Revenues are
recorded on the accrual basis including an estimate for gas delivered
but unbilled at the end of each accounting period. Columbia
Transmission also records the impact on revenues of the future
recovery or refund of differences between current gas and
transportation costs and amounts currently included in the billed
rates. In addition, Columbia Transmission and Columbia Gulf record
the effect on revenues to reflect the recovery or refund of
differences between current fuel usage and amounts retained.
2. REORGANIZATION PROCEEDINGS UNDER CHAPTER 11 OF THE BANKRUPTCY CODE
A. GENERAL. Under the Bankruptcy Code, actions by creditors to collect
prepetition indebtedness are stayed and other contractual obligations
may not be enforced against either the Corporation or Columbia
Transmission. As debtors-in-possession, both the Corporation and
Columbia Transmission have the right, subject to Bankruptcy Court
approval and certain other limitations, to assume or reject executory
contracts and unexpired leases. In this context, "rejection" means
that the debtor companies are relieved from their obligations to
perform further under the contract or lease but are subject to a claim
for damages for the breach thereof. Any claims for damages resulting
from rejection are treated as general unsecured claims in the
reorganization. The parties affected by these rejections may file
claims with the Bankruptcy Court in accordance with bankruptcy
procedures. Prepetition claims which were contingent or unliquidated
at the commencement of the Chapter 11 proceeding are generally
allowable against the debtor-in-possession in amounts fixed by the
Bankruptcy Court. Substantially all liabilities as of the petition
date are subject to resolution under plans of reorganization to be
approved by the Bankruptcy Court after submission to any required
vote by affected parties. The Corporation's reorganization plan also
requires approval by the Securities and Exchange Commission (SEC)
under the Public Utility Holding Company Act of 1935.
B. COLUMBIA TRANSMISSION'S PLAN OF REORGANIZATION. The Corporation's and
Columbia Transmission's discussions with the Official Committee of
Unsecured Creditors of Columbia Transmission (Columbia Transmission
Creditors' Committee) to negotiate a reorganization plan for Columbia
Transmission and expedite emergence from Chapter 11 proceedings had
been largely unsuccessful. Therefore, on January 18, 1994, Columbia
Transmission filed, with the Corporation as cosponsor, a
reorganization plan (plan) and a disclosure statement, for
consideration by its creditors and other interested parties. The
plan, which management believes is fair and equitable, proposes to pay
100 percent for all priority, administrative and secured claims and
offers various classes of general unsecured creditors, including
producers whose gas
63
64
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
contracts were rejected by Columbia Transmission, between 80 and 100
percent of Columbia Transmission's estimates of their allowable
claims. The $3.3 billion total distribution proposed in Columbia
Transmission's plan is based on an estimated value for Columbia
Transmission of $3.1 billion and includes significant financial
contributions by the Corporation. The plan is premised on a proposed
omnibus settlement whereby the Corporation would settle the
Intercompany Complaint (see page 65, C. Prepetition Obligations) and
facilitate Columbia Transmission's reorganization by (i) accepting the
value of the Corporation's secured claims against Columbia
Transmission in the form of secured debt and equity securities of
Columbia Transmission, and (ii) ensuring the cash (or at the option of
the Corporation cash and $100 million market value of the
Corporation's common stock) necessary to bring the aggregate
distribution to $3.3 billion. Creditors, other than the Corporation,
would share in distributions of over $1.2 billion in cash. In
addition, the Corporation would consent to the reorganized Columbia
Transmission's assumption of responsibility for public environmental
enforcement agency claims so that the recoveries of the other
creditors would not, with minor exceptions, be diminished by the
environmental liabilities of Columbia Transmission's estate.
The plan provides that Columbia Transmission will remain a
wholly-owned subsidiary of the Corporation, will continue to offer an
array of competitive transportation and storage services, and will
retain ownership of its 18,800-mile pipeline network and related
facilities.
Columbia Transmission's proposed business solution will offer to
producers, whose gas supply contracts were rejected or who have
prepetition claims under those contracts, individual, specific
settlements of the producers' claims that are based upon uniform
assumptions and principles and which, in the view of Columbia
Transmission's management, are fair and reasonable settlement values.
These specific settlement proposals are being developed and will be
filed as an adjunct to the plan. Columbia Transmission estimates that
aggregate distributions to producers under the plan would come to
approximately $900 million.
In general, the plan provides for immediate cash payment in full to
all priority claims, all secured claims held other than by the
Corporation, trust fund claims, administrative expenses and unsecured
claims of $50,000 or less. The Corporation's secured claims will be
satisfied in full with new secured debt and equity securities to be
issued by the reorganized Columbia Transmission. Unsecured claims
between $50,000 and $250,000 would receive 95 percent of their allowed
claims in cash. All other unsecured claims, including the
Corporation's unsecured debt and producer contract rejection claims,
would receive between 80 and 100 percent of their allowed claims based
on current projections. With respect to some of the classes of
creditors, the treatment described above depends on the acceptance of
the plan by the relevant class. At this time, no creditors have
agreed to any of the proposed plan's provisions, and the ultimate
confirmed plan of reorganization could be materially different from
this initial filing.
Although Columbia Transmission's plan utilizes June 30, 1994, as an
assumed date of emergence from bankruptcy, the actual date of
emergence will depend on the time required to complete the bankruptcy
process and obtain necessary creditor, judicial and regulatory
approvals. As part of its filing with the Bankruptcy Court, Columbia
Transmission requested that the court defer scheduling required
proceedings on the plan and related disclosure statement in order to
permit discussions of the plan, including the settlements proposed
therein, with Columbia Transmission's creditors, official committees
and other interested parties.
Under bankruptcy procedures, after Columbia Transmission's disclosure
statement has been approved by the Bankruptcy Court, the disclosure
statement and the reorganization plan will be sent to the company's
creditors for voting.
The Corporation intends to file a plan for its reorganization which
will be consistent with the financial aspects and structure of
Columbia Transmission's proposed plan of reorganization. Both plans
will be
64
65
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
subject to a lengthy review and approval process, including SEC
approval, and obtaining adequate financing.
Implementation of Columbia Transmission's plan, and the levels and
timing of distributions to its creditors, are subject to a number of
risk factors which could materially impact their outcome. The plan
sets forth numerous conditions to its confirmation and consummation.
The failure to satisfy these conditions in accordance with the terms
of the plan would have a material adverse effect on the outcome of
Columbia Transmission's bankruptcy and on the Corporation. These
conditions include, among others, the confirmation of a reorganization
plan for the Corporation, the receipt of necessary approvals for the
implementation of Columbia Transmission's plan and the recovery of
regulatory and tax benefits which are fundamental to the plan's
viability. Both companies anticipate emerging from bankruptcy at the
same time. The provisions of the reorganization plans of either
Columbia Transmission or the Corporation that are ultimately
implemented could be materially different from this initial filing for
Columbia Transmission and have a material adverse effect on the
Corporation and its subsidiaries and on the rights of shareholders and
holders of debt and other obligations.
C. PREPETITION OBLIGATIONS. Columbia Transmission's prepetition
obligations include secured and unsecured debt payable to the
Corporation, estimated supplier obligations, estimated rate refunds,
accrued taxes and other trade payables and liabilities. Prepetition
obligations of the Corporation primarily represent debentures, bank
loans and commercial paper outstanding on the filing date together
with accrued interest to that date. A substantial amount of Columbia
Transmission's liabilities subject to Chapter 11 proceedings relate to
amounts owed to the Corporation. Columbia Transmission's borrowings
have been funded by the Corporation on a secured basis since June 1985
and are secured by mortgages and a cash collateral order approved by
the Bankruptcy Court. On the petition date, the principal amount of
the First Mortgage Bonds outstanding was $930.4 million. Prepetition
and postpetition interest on secured debt owed by Columbia
Transmission to the Corporation is $346.4 million at December 31,
1993. In addition to these secured claims, the Corporation has an
unsecured claim against Columbia Transmission of $351 million in
installment notes issued prior to 1985 and accrued interest to the
petition date.
On March 19, 1992, the Columbia Transmission Creditors' Committee
filed a complaint (Intercompany Complaint) with the Bankruptcy Court
alleging that the $1.7 billion of Columbia Transmission's secured and
unsecured debt securities held by the Corporation should be
recharacterized as capital contributions (rather than loans) and
equitably subordinated to the claims of Columbia Transmission's other
creditors. The Intercompany Complaint also challenges interest and
dividend payments made by Columbia Transmission to the Corporation of
approximately $500 million for the period from 1988 to the petition
date and the 1990 property transfer from Columbia Transmission to
Columbia Natural Resources, Inc. (CNR) as an alleged fraudulent
transfer. Based on the SEC standardized measurement procedures, CNR's
properties had a reserve value of approximately $387 million as of
December 31, 1993, a significant portion of which is attributable to
the transfer from Columbia Transmission. In May 1992, Columbia
Transmission Creditors' Committee filed with the U.S. District Court
a motion for a jury trial and to move the Intercompany Complaint from
the Bankruptcy Court to the U. S. District Court. This motion was
denied and subsequently appealed to the Third Circuit Court of Appeals
(Third Circuit). In June 1992, the Corporation filed a motion with
the Bankruptcy Court seeking dismissal of, or summary judgment on,
principal portions of the Intercompany Complaint. On August 20, 1993,
the Third Circuit denied Columbia Transmission Creditors' Committee's
appeal, allowing the Bankruptcy Court to consider the merits of the
Intercompany Complaint and act upon the Corporation's June 1992 motion
for summary judgment. The Bankruptcy Court has not acted on the
Corporation's motion for summary judgment, but tentatively scheduled a
trial on the Intercompany Complaint to begin June 13, 1994.
Management believes that the Intercompany Complaint is without merit;
however, the ultimate outcome of these issues is uncertain at this
stage of the proceedings.
65
66
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Discussions with Columbia Transmission's creditors in an attempt to
establish the value of the estate and to resolve the matters raised in
the Intercompany Complaint are ongoing. Since the standing and value
of the Corporation's debt investment in Columbia Transmission is
crucial to the determination of the value of the Corporation's estate,
the Corporation's reorganization could be affected by the ultimate
outcome of the Intercompany Complaint.
The Internal Revenue Service (IRS) filed identical claims of $553.7
million against both debtor companies and the consolidated Columbia
Gas System for tax deficiencies, interest and penalties for the years
1983-1990. Negotiations with IRS representatives have resulted in a
settlement on all of the issues included in the IRS claims. This
settlement has been documented in a written closing agreement and
filed with the Joint Committee on Taxation of the U.S. Congress for
formal approval. The IRS settlement also requires Bankruptcy Court
approval. Recording the IRS settlement reduced 1993 net income by
$44.3 million.
Columbia Transmission has recorded liabilities of approximately $1.2
billion to reflect the estimated effects of its above-market producer
contracts and estimated supplier obligations associated with pricing
disputes and take-or-pay obligations for historical periods. With
Bankruptcy Court approval, Columbia Transmission rejected more than
4,800 above-market gas purchase contracts with producers. The
producers whose gas purchase contracts were rejected filed claims for
damages that, after being adjusted for duplicative and other erroneous
claims, are in excess of $13 billion. The Bankruptcy Court approved
the appointment of a claims mediator in 1992 to implement a claims
estimation procedure related to the rejected above-market producer
contracts and other producer claims. The mediator held hearings on
generic issues and various estimation methodologies and discovery
matters during 1993. Columbia Transmission anticipates that the
mediator may issue recommended determinations during the second
quarter of 1994 which, under the Bankruptcy Court-approved estimation
procedure, are expected to provide the basis for a recalculation of
producer contract rejection claims. In Columbia Transmission's
judgment, the positions taken by all producers before the claims
mediator and the evidence presented demonstrate that the total level
of allowable contract rejection claims, generically determined, will
not exceed 1/10th of the $13 billion asserted in the claims as filed
and is likely to be between $600 million and $950 million. The
acceptance of certain positions advanced by Columbia Transmission on
the evidence of record, as well as Columbia Transmission's as yet
unheard defenses, could decrease substantially this range of possible
aggregate outcomes. Resolution of the contract-specific issues not
yet presented could increase or decrease individual claims materially
but should not significantly alter the range of possible aggregate
outcomes.
The resolution of these issues can significantly influence future
reported financial results. Accounting standards require that as
claim amounts are allowed by the Bankruptcy Court, the full amount of
the allowed claim must be recorded. This could result in liabilities
being recorded which bear little relationship to the amounts
ultimately required to be paid in settlement of those claims and could
conceivably exceed the Corporation's total investment in Columbia
Transmission. Any such distortion would not be corrected until final
plans of reorganization are approved for the Corporation and Columbia
Transmission.
Regarding claims made by pipeline suppliers, on September 13, 1993,
the Bankruptcy Court approved an agreement between Columbia
Transmission and Texas Eastern Corporation (Texas Eastern) and the
settlement of related claims. Under the terms of this agreement,
Columbia Transmission will collect $30 million in refunds from Texas
Eastern and all claims filed by Texas Eastern against Columbia
Transmission, totalling $672 million, will be withdrawn. In November
1993, the Bankruptcy Court approved a settlement between Columbia
Transmission and Tennessee Gas Pipe Line Company (Tennessee). This
agreement provides for Columbia Transmission's assumption of certain
contracts, the termination of certain other contracts that are no
longer necessary for Columbia Transmission's operations, and payment
to Tennessee of approximately $42 million in consideration for
Tennessee's substantial reduction of its major transportation
contracts with Columbia Transmission. On January 11, 1994, Columbia
Transmission and Tennessee made a filing with the FERC to approve the
settlement. Columbia Transmission expects to ultimately recover the
costs and fees associated with the assumption and termination of these
contracts under
66
67
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Order 636. The Tennessee settlement agreement is conditioned upon
this recoverability. These settlements resolve a significant portion
of the pipeline supplier claims against Columbia Transmission.
The Pension Benefit Guaranty Corporation (PBGC) filed claims of $150
million against both the Corporation and Columbia Transmission
alleging that if the retirement plan had been terminated by March 31,
1992, it would have been underfunded. Management believes that the
claims made by the PBGC are inappropriate and in error since the
Bankruptcy Court has approved continued operation of the retirement
plan, required annual contributions are being made, there is no
intention to terminate the plan and the plan is not underfunded.
Management further believes that the PBGC's claim can be resolved
without any financial consequences to the Corporation or Columbia
Transmission. On January 29, 1993, the PBGC confirmed that while it
remains confident that issues regarding its claims can be resolved by
mutual agreement, the PBGC has decided not to proceed further with
settlement negotiations regarding withdrawal of its claims at the
present time due to the uncertainties associated with the bankruptcy
proceedings. At December 31, 1993, the date of the latest actuarial
valuation, plan assets exceeded the accumulated benefit obligations by
$166.5 million.
67
68
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The accompanying Consolidated Balance Sheets include approximately $4
billion of liabilities subject to the Chapter 11 proceedings of the
Corporation and Columbia Transmission as follows:
($ in millions) 1993 1992
----------------------------------------------------------------------------------------------------------
CORPORATION
Debentures:
6 1/4% Series due October 1991 12.0 12.0
6 5/8% Series due October 1992 7.4 7.4
7 1/4% Series due May 1993 15.0 15.0
9% Series due August 1993 150.0 150.0
7% Series due October 1993 12.0 12.0
9% Series due October 1994 20.2 20.2
8 3/4% Series due April 1995 16.2 16.2
9 1/8% Series due October 1995 22.0 22.0
10 1/8% Series due November 1995 18.6 18.6
8 3/8% Series due March 1996 32.9 32.9
9 1/8% Series due May 1996 18.6 18.6
8 1/4% Series due September 1996 26.4 26.4
7 1/2% Series due March 1997 23.3 23.3
7 1/2% Series due June 1997 26.3 26.3
7 1/2% Series due October 1997 28.4 28.4
7 1/2% Series due May 1998 23.7 23.7
10 1/4% Series due May 1999 25.0 25.0
9 7/8% Series due June 1999 21.8 21.8
10 1/4% Series due August 2011 100.0 100.0
10 1/2% Series due June 2012 200.0 200.0
10 3/20% Series due November 2013 100.0 100.0
9 1/5% to 9 1/2% Series A Medium-Term Notes due 1998 through 2019 200.0 200.0
8 19/20% to 9 49/50% Series B Medium-Term Notes due 1998 through 2020 200.0 200.0
9 11/20% to 9 37/50% Series C Medium-Term Notes due 2000 through 2020 50.0 50.0
----------------------------------------------------------------------------------------------------------
1,349.8 1,349.8
Unamortized debt discount, less premium (7.2) (7.2
----------------------------------------------------------------------------------------------------------
1,342.6 1,342.6
Subordinated Guarantee of Leveraged Employee Stock
Ownership Plan debt 87.0 87.0
Short-Term debt:
Commercial Paper 266.5 266.5
Bank Loans 621.0 621.0
----------------------------------------------------------------------------------------------------------
Prepetition debt obligations 2,317.1 2,317.1
Other 65.1 65.1
----------------------------------------------------------------------------------------------------------
Total 2,382.2 2,382.2
----------------------------------------------------------------------------------------------------------
Less amounts payable to affiliates 4.9 4.9
----------------------------------------------------------------------------------------------------------
TOTAL CORPORATION 2,377.3 2,377.3
----------------------------------------------------------------------------------------------------------
COLUMBIA TRANSMISSION
Debt obligations and other payables to the Corporation 2,028.9 1,890.8
Payables to other affiliates 70.0 67.1
Estimated supplier obligations 1,251.8 1,253.9
Estimated rate refunds 60.4 217.5
Taxes 98.4 44.5
Other 139.9 74.0
----------------------------------------------------------------------------------------------------------
Total 3,649.4 3,547.8
----------------------------------------------------------------------------------------------------------
Less amounts payable to affiliates 2,098.9 1,957.9
----------------------------------------------------------------------------------------------------------
TOTAL COLUMBIA TRANSMISSION 1,550.5 1,589.9
----------------------------------------------------------------------------------------------------------
TOTAL 3,927.8 3,967.2
----------------------------------------------------------------------------------------------------------
68
69
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
D. PAYMENT OF DIVIDENDS AND DEBT SERVICE. The Corporation's Board of
Directors suspended the payment of dividends on the Corporation's
common stock on June 19, 1991. The Corporation also discontinued
payments related to debt service. Columbia Transmission suspended
dividend, interest and debt payments to the Corporation. The
Corporation and Columbia Transmission have also suspended the payment
of most other prepetition obligations. Management cannot predict at
this time when or whether any financial restructuring plans will be
approved or what provisions, if any, such plans would contain as
related to the resumption of dividends, debt service and other
payments.
E. INTEREST EXPENSE. Interest expense of the Corporation is not being
accrued during bankruptcy, but a calculation of interest is included
in a footnote on the Statements of Consolidated Income and
Consolidated Balance Sheets. Such interest has been calculated based
on management's interpretation of the contractual arrangements which
govern the various debt instruments the Corporation has outstanding
exclusive of any redemption premiums. The Official Committee of
Unsecured Creditors of the Corporation has asserted claims for
interest which exceed disclosed amounts by approximately $40 million
at December 31, 1993. There are several factors to be considered in
making these calculations that are subject to uncertainty as to their
ultimate outcome in the bankruptcy proceeding, including the interest
rates and method of calculation to be applied to overdue payments of
principal and interest. In addition, the committee has asserted that
approximately $110 million of redemption premiums should be paid on
high cost debt instruments.
F. SECURITY HOLDER LITIGATION. After the announcement on June 19, 1991,
regarding the Corporation's probable charge to second quarter earnings
and the suspension of its dividend, 17 complaints including purported
class actions were filed against the Corporation and its directors and
certain officers of the debtor companies in the U.S. District Court of
Delaware. The actions, which generally allege violations of certain
anti-fraud provisions of the Securities Act of 1933 and the Securities
Exchange Act of 1934, have been consolidated. In addition, three
derivative actions were filed in the Court of Chancery in and for New
Castle County (Delaware) alleging that directors breached their
fiduciary duties. These suits have been stayed by either the
Bankruptcy Court filing or by stipulation of the parties. While the
Corporation believes that it has meritorious defenses to these
actions, the outcome is uncertain at this time.
G. CUSTOMER RECOUPMENT RIGHTS. During the fourth quarter of 1993,
various customers of Columbia Transmission filed motions with the
Bankruptcy Court seeking authority to exercise alleged recoupment and
setoff rights, whereby they would be permitted to reduce amounts owed
to Columbia Transmission against refunds owed to the customers by
Columbia Transmission, including amounts which were not otherwise
payable in full under the July 1993 Third Circuit decision discussed
below, all customer refunds under the 1990 rate case settlement and
miscellaneous refunds not otherwise payable in full to them.
Customers are alleging that they have recoupment and setoff rights of
approximately $83 million at December 31, 1993.
On October 20, 1993, the Bankruptcy Court approved an interim
settlement under which customers continued to pay Columbia
Transmission for FERC-authorized services at authorized rates, and
Columbia Transmission has agreed to grant these customers a priority
claim to the extent the Bankruptcy Court finds them entitled to
recoupment rights. In January 1994, the Bankruptcy Court issued a
procedural order whereby other customers would be permitted to file
recoupment and setoff motions by February 18, 1994, with a trial on
all such motions scheduled for June 1994.
H. CUSTOMER REFUNDS. In July 1993, the Third Circuit overturned most of
a U.S. District Court ruling and affirmed an earlier Bankruptcy Court
decision that refunds Columbia Transmission received from upstream
pipelines, as well as the Gas Research Institute (GRI) surcharge
payments it collected from customers, are held in trust, by Columbia
Transmission, for those customers and the GRI and are not part of
Columbia Transmission's estate. In August 1993, the Third Circuit
denied the Columbia Transmission Creditors' Committee's request for a
rehearing. In February 1994, the Supreme Court denied petitions for
review of the Third Circuit decision.
69
70
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Under the Third Circuit ruling, approximately $173 million in refunds
that Columbia Transmission has received, or expects to receive
postpetition from upstream pipelines and GRI surcharges collected,
should be passed through to the customers and to the GRI. In
addition, the Third Circuit determined that $35 million in upstream
pipeline refunds and GRI surcharges, which Columbia Transmission
collected prior to filing Chapter 11 while received in trust, were
subject to the "lowest intermediate cash balance test" (the amount
remaining in trust at the time of bankruptcy) and should be
distributed on a pro rata basis to the customers and to the GRI to the
extent of Columbia Transmission's $3.3 million cash balance on July
31, 1991. The Third Circuit affirmed another part of the U.S.
District Court's decision and held that approximately $16 million that
Columbia Transmission owes upstream suppliers, for gas purchased and
transportation services received prior to its bankruptcy filing, is
ordinary unsecured debt which must be discharged in the bankruptcy
process.
On February 10, 1994, the U.S. District Court issued an order for the
Bankruptcy Court to pursue further proceedings in accordance with the
Third Circuit's refund decision directing the pass-through of these
refunds. At a hearing on December 29, 1993, the Bankruptcy Court
observed that the FERC should determine whether customers are entitled
to the actual interest earned on refunds being held by Columbia
Transmission or the higher FERC-prescribed interest rate. On February
18, 1994, Columbia Transmission filed a motion with the FERC for
determination of the interest issue. Columbia Transmission will ask
the Bankruptcy Court for implementation of the mandate. Columbia
Transmission will also have to file with the FERC to reimplement its
flow-through of Order Nos. 500/528 refunds from its pipeline
suppliers, which represent the majority of the refunds at issue. It
is anticipated that Columbia Transmission will recommence the
flow-through of the upstream pipeline refunds in 1994.
Total customer claims in Columbia Transmission's bankruptcy
proceedings relating to, or arising from, Columbia Transmission's
contracts with its customers for sales, transportation, gas storage
and similar services and other miscellaneous claims represent about
450 claims for a total of approximately $550 million as filed, plus a
potentially substantial sum filed in undetermined amounts. Columbia
Transmission successfully resolved a significant portion of these
customers claims. Not resolved are customer claims that total
approximately $113 million at December 31, 1993, that seek to protect
rights associated with any prepetition revenues collected subject to
refund in general rate filings and purchased gas adjustment filings,
including matters subject to court appeals. In addition, the claims
filed in undetermined amounts, which potentially could be significant,
still remain to be resolved. In October 1993, approximately $160
million was refunded to customers by Columbia Transmission reflecting
the terms of a settlement of a 1991 rate case approved by the
Bankruptcy Court in July 1993. Bankruptcy Court approval for a 1990
rate case settlement for rates in effect from November 1, 1990 through
November 30, 1991 was deferred pending the decision by the Third
Circuit regarding the flow- through of certain refunds. Appropriate
reserves for rate refund liabilities have been recorded for these
matters to reflect management's judgment of the ultimate outcome of
the proceedings.
I. REORGANIZATION ITEMS. During 1993, 1992 and 1991 the Corporation and
Columbia Transmission have earned interest income on cash accumulated
from the suspension of payments related to prepetition liabilities and
incurred expenses associated with professional fees and other related
services, as detailed below:
($ in millions) 1993 1992 1991
-----------------------------------------------------------------------------------------------------
Interest income on accumulated cash 39.9 26.9 4.5
Professional fees and related expenses (29.9) (30.7) (18.8)
Other reorganization items, net (1.1) (4.5) (0.1)
------------------------------------------------------------------------------------------------------
NET REORGANIZATION ITEMS 8.9 (8.3) (14.4)
------------------------------------------------------------------------------------------------------
70
71
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
J. FINANCIAL INFORMATION FOR THE DEBTOR COMPANIES. Condensed financial
information for the Corporation and Columbia Transmission as of, and
for, periods ended December 31, are as follows:
Corporation Columbia Transmission
-------------------------- -----------------------
($ in millions) 1993 1992 1993 1992
------------------------------------------------------------------------------------------------------
Current assets
Cash and temporary
cash investments 128.7 8.0 1,209.2 804.6
Other 168.7 429.1 461.8 637.9
Total current assets 297.4 437.1 1,671.0 1,442.5
Current liabilities (19.2) (16.8) (629.6) (449.6)
------------------------------------------------------------------------------------------------------
Working capital 278.2 420.3 1,041.4 992.9
Noncurrent assets 3,476.4 3,119.7 2,269.4 2,225.1
Estimated liabilities subject
to Chapter 11 proceedings (2,382.2) (2,382.2) (3,649.4) (3,547.8)
Noncurrent liabilities (145.1) (82.7) (178.6) (169.2)
------------------------------------------------------------------------------------------------------
NET EQUITY 1,227.3 1,075.1 (517.2) (499.0)
------------------------------------------------------------------------------------------------------
Operating revenues - - 1,654.5 1,363.8
Operating expenses 7.1 10.3 (1,433.6) (1,256.9)
------------------------------------------------------------------------------------------------------
Operating income (loss) (7.1) (10.3) 220.9 106.9
Other income (deductions) 219.0 154.7 (216.3) (118.0)
Income taxes 59.7 53.5 22.8 6.5
Extraordinary item - (39.7) - -
------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) 152.2 51.2 (18.2) (17.6)
------------------------------------------------------------------------------------------------------
NET CASH FROM OPERATIONS 64.8 59.4 502.0 510.3
------------------------------------------------------------------------------------------------------
3. REGULATORY MATTERS
A. Columbia Transmission has collected revenues from its customers
associated with the pass-through of upstream pipeline supplier take-
or-pay and contract reformation costs under FERC Order Nos. 500 and
528. Certain customers have challenged recovery of such costs which
totals $160 million, (excluding interest) net of amounts to be
refunded, on the basis that a 1985 rate settlement precludes
collection. The FERC has consistently denied the customers'
assertions and appeals have been filed with the U.S. Court of Appeals,
D.C. Circuit. Management continues to believe these challenges are
without merit and the FERC orders, which support collection of these
costs, will ultimately be upheld.
B. In April 1992, the FERC issued Order 636, its final rule on Pipeline
Service Obligations and Equality of Transportation Services by
Pipelines. This order fundamentally changes the role of pipelines
from providing a merchant function to one in which they perform
principally as transporters of gas that distribution companies and end
users purchase directly from producers and other suppliers.
While Order 636 provided that pipelines may recover all prudently
incurred costs resulting from the transition to Order 636, the FERC
stated that filings to recover such costs should not be made until a
pipeline's service restructuring proposal, that identifies various
transition costs, has been approved. With respect to gas supply
realignment costs, costs associated with reforming or terminating
above-market price supply contracts, Columbia Transmission noted in
its filing that the majority of such costs on its system will be
determined in the context of the bankruptcy proceedings regarding the
treatment of producer
71
72
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
contract rejection costs. The company stated that the ultimate level
of such costs is uncertain and that recovery would be pursued in
future filings with the FERC.
In 1993, the FERC issued a series of orders on the restructuring
proposals and on September 29, 1993, the FERC issued an order which
allowed Columbia Transmission and Columbia Gulf to implement
restructured services on November 1, 1993. While confirming its
initial ruling regarding the ineligibility for recovery of producer
contract rejection costs as gas supply realignment or Order Nos.
500/528 costs, the FERC did rule that Columbia Transmission could
seek to recover a small portion of the contract rejection costs that
had earlier been ruled to be unrecoverable. The FERC also agreed to
waive a nine-month time limit on Columbia Transmission's ability to
seek recovery of unrecovered purchased gas costs to the extent the
costs resulted from contracts that are currently in litigation,
including bankruptcy litigation. Approximately $60 million in
unrecovered purchased gas costs were outstanding at December 31, 1993,
in addition to approximately $140 million of prepetition unrecovered
purchased gas costs that have not been paid due to the bankruptcy
filing.
The FERC affirmed that Columbia Transmission could maintain recovery
of gathering costs through its gathering and other transportation
rates at least until the filing of a general rate case and approved a
separate charge applicable to product extraction activities.
Management continues to evaluate long-term plans for these gathering
facilities ($63.3 million at December 31, 1993).
Subject to review in connection with periodic rate filings, the FERC
approved Columbia Transmission's proposal to continue to recover costs
associated with retained upstream pipeline contracts through its
demand rates. Recovery of such costs would be subject to review and
approval in semiannual limited rate filings. Columbia Transmission
has reached settlements that will eliminate approximately half of the
annual cost of these contracts and is continuing its efforts to
negotiate a mutually agreeable termination of the remainder of the
contracts.
The FERC also addressed Columbia Transmission's ability to recover
costs associated with upstream pipeline contracts. Columbia
Transmission currently holds firm transportation agreements with
certain pipeline companies that historically have been used to deliver
gas to Columbia Transmission. These contracts have remaining terms of
various lengths and require the payment of monthly reservation fees
whether or not the capacity is utilized. Under Order 636, downstream
pipelines such as Columbia Transmission are required to offer to
assign most of their firm upstream capacity to their customers.
Columbia Transmission's annual demand charge commitments on these
upstream nonaffiliated pipelines was approximately $108 million;
however, assignments of certain of these contracts by Columbia
Transmission to its customers in conjunction with service
restructuring under Order 636 have reduced this amount to less than
$74 million. The total commitment for demand charges after November
1, 1993, is approximately $421 million on an undiscounted basis,
excluding any mitigating effect of the pipelines marketing the
capacity to others.
Columbia Transmission's strategy has been to assume all upstream
pipeline contracts that can be directly assigned to its customers or
need to be retained by Columbia Transmission for operational reasons
and negotiate exit fees for other upstream contracts. The FERC ruling
in the Order 636 proceedings permits recovery of these exit fees
through rates, provided that Columbia Transmission can show that they
are prudently incurred. Columbia Transmission retains the option of
rejecting such contracts in its bankruptcy proceedings, if appropriate
exit fees cannot be negotiated. The financial statements reflect a
$130 million liability and offsetting receivable for the exit fee
issue; however, the ultimate cost could vary depending on the outcome
of ongoing discussions with the affected pipelines.
Several settlements with upstream pipelines have been concluded. In
1993, the Bankruptcy Court approved
72
73
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
settlements between Columbia Transmission and Texas Eastern
Transmission Corporation, Panhandle Eastern Pipe Line Company and
Texas Gas Transmission Corporation which provide for assumption of
certain contracts and termination of others. None of these
settlements required Columbia Transmission to pay an exit fee to the
upstream pipeline.
One type of transition cost which the FERC acknowledged would be
eligible for recovery consideration is "stranded costs", which are the
costs of a pipeline's assets previously used to provide bundled sales
service in the pre-Order 636 era, that are unsubscribed in the Order
636 environment. Columbia Gulf has several pipelines and related
facilities that are not fully subscribed to under Order 636. Certain
facilities south of Rayne, Louisiana, (primarily in the offshore Gulf
of Mexico area) are being evaluated; however, management has not
identified any stranded facilities at this time and the outcome of
these evaluations is uncertain. Dependent upon the results of such
evaluation, charges to income could be required. The net book value
of the facilities under study was approximately $40 million at
December 31, 1993. It is management's view that any costs associated
with these facilities will be fully recoverable through rates.
As part of its September 29, 1993 order on Columbia Transmission's and
Columbia Gulf's Order 636 compliance filings, the FERC initiated a
proceeding concerning Columbia Gulf's transportation service to
Columbia Transmission. Columbia Gulf was directed to show cause as to
why it has not filed for abandonment to reduce capacity and service to
Columbia Transmission under the required FERC authorization under
Section 7(b) of the Natural Gas Act. Columbia Gulf responded to the
show cause order on December 22, 1993. Management does not believe an
abandonment filing was necessary and does not expect the resolution of
this issue to have a material adverse effect on the Corporation's
financial position.
C. On January 12, 1994, the FERC granted requests for rehearing of prior
orders approving settlements between Columbia Transmission and four of
its upstream pipeline suppliers relating to those suppliers' direct
billings to Columbia Transmission in the mid-1980s of
production-related FERC Order No. 94 (Order 94) costs. The rehearing
orders find that the settlements must be rejected because they are
expressly contingent upon Columbia Transmission's recovery of the
Order 94 settlement payments from its customers, and that Columbia
Transmission's 1985 PGA Settlement essentially bars such recovery.
However, the orders also hold that these pipelines are not entitled to
bill any Order 94 charges to Columbia Transmission, and ordered these
upstream pipelines to refund the principal portion of all Order 94
collections from Columbia Transmission, but waived any requirements
that these pipelines pay interest on the refunds. Since Columbia
Transmission has been reflecting the interest income on these refunds
since 1990, the effect of these orders led to a $19.5 million
reduction in interest income in 1993. Columbia Transmission has
sought rehearing and, if necessary, will seek court review of these
orders. It is expected that pipeline suppliers will also request a
rehearing arguing their rights to re-bill such charges to Columbia
Transmission. The ultimate outcome of this issue is uncertain at this
time and could impact future operating results depending upon the
results of these regulatory and court reviews.
73
74
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
4. ACCOUNTING CHANGES
A. In the fourth quarter of 1991, the Corporation adopted SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other Than
Pensions" (OPEB), retroactive to January 1, 1991. This method of
accounting for postretirement benefits accrues the actuarially
determined costs for life insurance and medical benefits ratably from
the date an employee becomes eligible for such benefits. The
Corporation's subsidiaries previously expensed these costs as cash
payments were made. As permitted under SFAS No. 106, the subsidiaries
elected to record the full amount of their estimated accumulated
postretirement benefits obligation other than pensions of $223.8
million. These obligations represent the actuarial present value of
the postretirement benefits to be paid to current employees and
retirees based on services rendered.
The present value of the postretirement benefit obligation to be paid
to current and retired employees for all the distribution subsidiaries
amounts to approximately $143 million as of December 31, 1993. Of
this amount, $138.1 million has been deferred as a regulatory asset
pending anticipated recovery through rates in various jurisdictions.
The Emerging Issues Task Force (EITF) of the Financial Accounting
Standards Board issued guidelines establishing criteria for recording
such a regulatory asset, including a requirement for collection of
accrual basis expense in rates and recovery of the transition
obligation within approximately 20 years. These criteria are not
necessarily being adopted by the public utility commissions regulating
the distribution subsidiaries. Differences in requirements between
the accounting rules and the rate making decisions ultimately adopted
can result in a writedown of some of this regulatory asset.
The distribution subsidiaries, as well as the Corporation's other
operating companies, have implemented cost-management measures
designed to reduce their OPEB obligations. In addition to other
measures, employees will be required to share a portion of their
postretirement health benefit costs and guidelines have been
established redefining years of service requirements before an
employee is eligible for retiree health benefits. Other cost-saving
plans are being reviewed for consideration in an ongoing effort to
effectively manage OPEB costs.
The regulatory commission in Ohio issued a final order in February,
1993 in a generic rate investigation regarding recovery of
postretirement benefit costs. The commission's order provides
utilities the opportunity to fully recover prudently incurred
postretirement costs on an accrual basis. Amounts in excess of
pay-as-you-go costs may continue to be deferred until rate recovery
begins. The amount of the Columbia Gas of Ohio regulatory asset in
the accompanying balance sheet was $85.6 million as of December 31,
1993.
In March 1993, the Pennsylvania PUC stated in a proposed policy
statement that any utility in its jurisdiction meeting certain
conditions may seek formal PUC approval to record a regulatory asset
equal to the difference between its current rate recognition of
postretirement benefit costs and its accrued liability for such
expenses. The amounts recorded will be subject to recovery in future
rate proceedings to the extent that such costs are prudently incurred
and certain conditions are met, such as dedicated funding of
postretirement costs in excess of the pay-as-you-go level. Columbia
Gas of Pennsylvania's (CPA) petition to maintain the postretirement
benefit deferred regulatory asset until rate recovery begins was
granted in December, 1993. This order gave CPA the permission to
recover transition costs over 20 years. At December 31, 1993, the
carrying value of CPA's regulatory asset was approximately $33.1
million.
The Kentucky state commission has indicated that the rate treatment of
accrued postretirement benefits will be addressed on a company-
by-company basis. Management believes Columbia Gas of Kentucky (CKY)
will ultimately obtain recovery authorization based on a recent
commission rate order for another utility, holding that recovery of
these costs on an accrual basis better reflects the true cost of
providing service to current customers. CKY will continue to defer
its postretirement benefit costs in excess of the pay-as-you-go
amount, pending the filing of its next general rate case which is
currently scheduled for mid-1994. At December 31, 1993, the carrying
value of CKY's regulatory asset was approximately $9.8 million.
74
75
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Commonwealth Gas Services (COS) placed interim rates into effect June
1, 1993, subject to refund, which included recovery of accrued OPEB
costs. Indications from the Virginia State Corporation Commission
(VSCC) are that the costs will be deemed prudent and recoverable
according to the commission's 1992 generic order addressing
postretirement costs. As a result of the recovery of transition costs
over a period of 40 years, the EITF guidelines required COS to expense
$4.2 million in 1992.
Columbia Gas of Maryland's (CMD) general rate case settlement,
effective October 1993, allows CMD to include in rates the full amount
of accrued postretirement benefit costs as well as the recovery of the
transition obligation over 20 years.
Although proceedings in certain state jurisdictions have yet to be
finalized, based on currently available information, management
believes rate recovery mechanisms will be adopted that permit
continued regulatory asset treatment in accordance with recent EITF
guidelines.
B. In February 1992, the Financial Accounting Standards Board issued SFAS
No. 109, "Accounting for Income Taxes." The Corporation adopted SFAS
No. 109 in the fourth quarter of 1992, retroactive to January 1, 1992.
This Statement supersedes SFAS No. 96, "Accounting for Income Taxes,"
which was adopted by the Corporation in 1991 and improved earnings by
$170 million. SFAS No. 109 changes the criteria for recognition and
measurement of deferred tax assets and reduces complexity. The
adoption of SFAS No. 109 had no impact on the Corporation's financial
statements.
C. In November 1992, the Financial Accounting Standards Board issued SFAS
No. 112, "Employers' Accounting for Postemployment Benefits." This
Statement requires employers to recognize any obligation which exists
to provide benefits to former or inactive employees after employment,
but before retirement. Such benefits include, but are not limited to,
salary continuation, supplemental unemployment, severance, disability
(including workers' compensation), job training, counseling, and
continuation of benefits such as health care and life insurance
coverage.
This Statement will be effective for fiscal years beginning after
December 15, 1993, and the Corporation plans to adopt the Statement on
January 1, 1994. Based on the facts and circumstances known today,
the total obligation to the Corporation and its subsidiaries will be
approximately $8.8 million. Of this amount, approximately $5.4
million will be expensed upon adoption. The remaining $3.4 million
will be deferred by certain of the distribution subsidiaries as a
regulatory asset pending rate recovery from the various state
commissions.
75
76
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
5. INCOME TAXES
The components of income tax expense are as follows:
Year Ended December 31 ($ in millions) 1993 1992 1991
------------------------------------------------------------------------------------------------
INCOME TAXES
Currently payable
Federal 107.2 90.0 106.7
State 9.6 10.8 8.0
------------------------------------------------------------------------------------------------
Total Currently Payable 116.8 100.8 114.7
------------------------------------------------------------------------------------------------
Deferred
Federal 17.6 (32.2) (510.2)
State 2.3 3.3 (13.7)
------------------------------------------------------------------------------------------------
Total Deferred 19.9 (28.9) (523.9)
------------------------------------------------------------------------------------------------
Deferred Investment Credits (0.8) (1.4) (1.8)
------------------------------------------------------------------------------------------------
Income taxes included in income before extraordinary item and
cumulative effect of accounting changes 135.9 70.5 (411.0)
Deferred taxes related to extraordinary item and cumulative
effect of accounting changes - (20.4) (236.6)
------------------------------------------------------------------------------------------------
TOTAL INCOME TAXES 135.9 50.1 (647.6)
------------------------------------------------------------------------------------------------
Total income taxes are different than the amount which would be
computed by applying the statutory Federal income tax rate to book
income before income tax. The major reasons for this difference are
as follows:
Year Ended December 31 ($ in millions) 1993 1992 1991
----------------------------------------------------------------------------------------------------------------
Book income (loss) before incomes taxes, extraordinary
item and cumulative effect of accounting changes* 288.1 161.4 (1,205.8)
Tax expense (benefit) at statutory Federal income tax
rate 100.8 35.0% 54.9 34.0% (410.0) (34.0)%
Increases (reductions) in taxes resulting from:
State income taxes, net of Federal income tax benefit 7.6 2.7 9.8 6.1 (4.7) (0.4)
Estimated non-deductible expenses 8.1 2.8 6.4 4.0 3.3 0.3
Effect of change in tax rates on deferred taxes
previously provided 8.7 3.0 - - - -
Adjustment to prior years' tax provision due to
pending settlement 9.2 3.2 - - - -
Other 1.5 0.5 (0.6) (0.4) 0.4 -
----------------------------------------------------------------------------------------------------------------
INCOME TAXES BEFORE EXTRAORDINARY ITEM AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGES 135.9 47.2% 70.5 43.7% (411.0) (34.1)%
----------------------------------------------------------------------------------------------------------------
*Includes losses from foreign operations of $41.5 million for 1991.
76
77
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Deferred tax balances are as follows:
At December 31 ($ in millions) 1993 1992
---------------------------------------------------------------------------------------------
Net current liabilities (assets)
Federal (3.9) 20.5
State (0.7) (0.8)
---------------------------------------------------------------------------------------------
Total (4.6) 19.7
---------------------------------------------------------------------------------------------
Net noncurrent liabilities
Federal 190.7 128.7
State 63.1 61.6
---------------------------------------------------------------------------------------------
Total 253.8 190.3
---------------------------------------------------------------------------------------------
TOTAL DEFERRED INCOME TAXES 249.2 210.0
---------------------------------------------------------------------------------------------
Deferred income taxes result from temporary differences between the
financial statement carrying amounts and the tax basis of existing
assets and liabilities. The source of these differences and tax
effect of each is as follows:
At December 31 ($ in millions) 1993 1992
---------------------------------------------------------------------------------------------
Property basis differences 613.5 595.2
Accrued interest on debt 147.0 85.3
Gas purchase costs 63.0 51.5
Partnership deferrals 25.4 26.7
Deferred revenue 11.0 23.0
Estimated supplier obligations (343.8) (338.9)
Estimated rate refunds (85.4) (100.4)
Postretirement benefits (46.1) (44.7)
Environmental liabilities (57.1) (38.4)
Capitalized inventory overheads (26.2) (26.7)
Unbilled utility revenue (7.5) (15.1)
Interest on prior years' taxes (27.0) (2.2)
Other (17.6) (5.3)
---------------------------------------------------------------------------------------------
TOTAL DEFERRED INCOME TAXES 249.2 210.0
---------------------------------------------------------------------------------------------
6. SALE OF SUBSIDIARIES
A. The sale of Columbia Gas of New York, Inc. to New York State Electric
& Gas Corporation was completed on April 5, 1991, and provided an
increase to net income of $9.2 million. The total price was $57.5
million including $39.2 million for the 328,000 outstanding shares of
common stock and $18.3 million for the outstanding debt.
B. The sale of Columbia Gas Development of Canada Ltd. (Columbia Canada),
a wholly-owned Canadian oil and gas exploration and production
subsidiary, to Anderson Exploration, Ltd. was effective as of December
31, 1991.
The sales price for Columbia Canada was $94.8 million. Of this
amount, $27.7 million was placed in escrow as security for certain
post-closing obligations of the Corporation including indemnification
for potential losses arising from litigation involving Columbia
Canada. The Corporation expects to receive all or substantially all
of the escrow account when the litigation is concluded. Upon
emergence from bankruptcy, the Corporation is obligated to deposit
into an escrow account an additional $25 million (Canadian). If after
emergence from bankruptcy, the Corporation maintains an investment
grade bond rating for a six-month period, the additional deposit would
be
77
78
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
returned. Also, the Corporation has the right to provide a letter of
credit in place of the cash deposit. As of December 31, 1993, $25.4
million, including accrued interest, remains in escrow for potential
losses arising from litigation.
7. PENSION AND OTHER POSTRETIREMENT BENEFITS
The Corporation has a trusteed, noncontributory pension plan which
covers all regular employees, 21 years of age and older. The plan
provides defined benefits based on the highest three-year average
annual compensation in the final five years of service and years of
credited service. It is the Corporation's funding policy to
contribute to the plan based on a percentage of payroll, subject to
the statutory minimum and maximum limits.
The following table provides 1993-1991 pension cost components for the
plan, along with additional relevant data:
PENSION COSTS ($ in millions) 1993 1992 1991
------------------------------------------------------------------------------------------------
Service cost 31.7 30.5 21.7
Interest cost 68.8 66.1 63.2
Actual return on assets (126.9) (55.8) (171.7)
Net amortization (deferral) 56.5 (13.2) 115.0
------------------------------------------------------------------------------------------------
NET PENSION EXPENSE 30.1 27.6 28.2
------------------------------------------------------------------------------------------------
ANNUAL CONTRIBUTION 18.0 23.5 24.0
------------------------------------------------------------------------------------------------
ASSUMED ASSET EARNINGS RATE 9.0% 9.0% 9.0%
------------------------------------------------------------------------------------------------
78
79
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Pension plan assets consist principally of common stock equities and
fixed income securities. The following table reconciles plan assets
and liabilities to the funded status of the plan:
PLAN ASSETS AND OBLIGATIONS at December 31 ($ in millions) 1993 1992
------------------------------------------------------------------------------------------------
Plan assets at fair value 945.2 860.2
------------------------------------------------------------------------------------------------
Actuarial present value of benefit obligations:
Vested benefits 729.4 668.2
Nonvested benefits 49.3 47.5
------------------------------------------------------------------------------------------------
Accumulated benefit obligation 778.7 715.7
Effect of projected future salary increases 201.5 199.9
------------------------------------------------------------------------------------------------
TOTAL PROJECTED BENEFIT OBLIGATION 980.2 915.6
------------------------------------------------------------------------------------------------
Plan assets less than projected benefit obligation (35.0) (55.4)
Unrecognized net gain (44.4) (18.1)
Unrecognized prior service cost 65.0 69.7
Unrecognized transition obligation 10.4 11.6
------------------------------------------------------------------------------------------------
PREPAID (ACCRUED) PENSION COST (4.0) 7.8
------------------------------------------------------------------------------------------------
DISCOUNT RATE ASSUMPTION 7.0% 7.5%
------------------------------------------------------------------------------------------------
AVERAGE COMPENSATION GROWTH RATE 5.5% 6.0%
------------------------------------------------------------------------------------------------
As of December 31, 1993 the assumptions for the discount rate and the
average compensation growth rate have been revised downward to 7.0%
and 5.5%, respectively. The net effect of these changes was to
increase the accumulated benefit obligation and the projected benefit
obligation by $42.2 and $38.2 million, respectively.
79
80
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
In addition to providing pension benefits, the Corporation's
subsidiaries provide other postretirement benefits, including medical
care and life insurance, which cover substantially all active
employees upon their retirement. The following table provides the
total postretirement benefit cost components recognized during 1993
and 1992 along with additional relevant data:
OTHER POSTRETIREMENT COSTS ($ in millions) 1993 1992
-----------------------------------------------------------------------------------------
Service cost (benefits earned during period) 16.2 13.3
Interest cost on projected benefit obligation 25.9 22.5
Actual return on assets (12.6) (2.9)
Other, net 7.8 (0.4)
-----------------------------------------------------------------------------------------
OTHER POSTRETIREMENT COSTS 37.3 32.5
-----------------------------------------------------------------------------------------
ASSUMED ASSET EARNINGS RATE* 9.0% 9.0%
-----------------------------------------------------------------------------------------
*One of the several established medical trusts is subject to taxation
which results in an after-tax asset earnings rate that is less than
9.0%.
PLAN ASSETS AND OBLIGATIONS AT DECEMBER 31 ($ in millions)*
------------------------------------------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retirees 188.1 179.7
Fully eligible active plan participants 72.0 68.2
Other participants 89.7 86.7
------------------------------------------------------------------------------------------------
Total 349.8 334.6
Plan assets at fair value (79.9) (54.0)
Unrecognized actuarial loss (9.4) (30.8)
------------------------------------------------------------------------------------------------
ACCRUED POSTRETIREMENT BENEFIT COST 260.5 249.8
------------------------------------------------------------------------------------------------
DISCOUNT RATE ASSUMPTION 7.0% 7.5%
------------------------------------------------------------------------------------------------
AVERAGE COMPENSATION GROWTH RATE 5.5% 6.0%
------------------------------------------------------------------------------------------------
* Includes $138.1 million and $127.2 million capitalized by the
distribution subsidiaries as a regulatory asset in 1993 and 1992,
respectively.
As of December 31, 1993, the assumptions for the discount rate and the
average compensation growth rate have been revised downward to 7.0
percent and 5.5 percent, respectively. The net effect of these
changes was an $11.0 million increase in the accumulated
postretirement benefit obligation.
The healthcare cost trend rate assumption significantly affects the
amounts reported. For example, a 1 percent increase in this rate
would increase the accumulated postretirement benefit obligation by
$19.0 million at December 31, 1993, and increase other postretirement
costs by $3.7 million for the year. The accumulated
80
81
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
postretirement benefit obligations for 1993 and 1992 were calculated
assuming healthcare cost trend rates starting at 12 percent and 16
percent and decreasing to 5.5 percent and 6.5 percent, respectively,
after approximately 25 years.
The postretirement medical plans of the majority of the Corporation's
subsidiaries are currently funded on a pay-as-you-go basis. However,
several subsidiaries have begun advanced funding as this benefit
obligation is granted rate recovery. A total of $16.9 million and
$13.0 million were contributed to the various medical trusts in 1993
and 1992, respectively.
All of the Corporation's subsidiaries participate in funding for
postretirement life insurance benefits utilizing a voluntary employee
beneficiary association trust. The Corporation's funding policy is to
make annual contributions to this trust, subject to the statutory
maximum tax-deductible limit. Employee contributions are not
required.
8. LONG-TERM INCENTIVE PLAN
The Corporation has a Long-Term Incentive Plan (Plan) which provides
for the granting of nonqualified stock options, stock appreciation
rights and contingent stock awards as determined by the Compensation
Committee of the Board of Directors. That committee also has the
right to modify any outstanding award. A total of 1,500,000 shares of
the Corporation's authorized common stock was initially reserved for
issuance under the Plan's provisions. There were 363,415 shares
remaining available for awards at December 31, 1993.
Stock appreciation rights, which are granted in connection with
certain nonqualified stock options, entitle the holders to receive
stock, cash or a combination thereof equal to the excess market value
over the grant price.
81
82
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Transactions for the three years ended December 31, 1993, are as follows:
Options
--------------------------------------
Without Stock With Stock Option
Appreciation Appreciation Price
Rights Rights Range
-------------------------------------------------------------------------------------------------------
Outstanding 12/31/90 597,155 165,090 $34.30-$46.68
-------------------------------------------------------------------------------------------------------
1991
Granted - - -
Exercised (12,065) (1,440) $34.30-$42.99
Cancelled (21,330) - $34.30-$46.68
Converted - - -
Outstanding 12/31/91 563,760 163,650 $34.30-$46.68
-------------------------------------------------------------------------------------------------------
1992
Granted - - -
Exercised - - -
Cancelled (34,410) - $34.30-$46.68
Converted - - -
Outstanding 12/31/92 529,350 163,650 $34.30-$46.68
-------------------------------------------------------------------------------------------------------
1993
Granted - - -
Exercised - - -
Cancelled (23,730) (7,500) $34.30-$46.68
Converted - - -
Outstanding 12/31/93 505,620 156,150 $34.30-$46.68
-------------------------------------------------------------------------------------------------------
EXERCISABLE 12/31/93 432,070 133,650 $34.30-$46.68
-------------------------------------------------------------------------------------------------------
In addition to the options, a contingent stock award of 4,110 shares was
granted to a key executive in 1991 which remains outstanding at December
31, 1993.
9. DEFINED CONTRIBUTION (THRIFT) PLAN
Eligible employees may participate in the Thrift Plan by contributing up
to 16 percent of their monthly basic earnings to any one or more of
several funds. The Corporation's participating subsidiaries make
matching contributions of 50 percent to 100 percent of deposits made by
each of its participating employees up to 6 percent of basic earnings
based upon the months of participation in the plan by each employee. All
employer matching contributions for participants under age 55 are
invested in the fund holding common stock of the Corporation.
Participants age 55 and older may invest employer contributions in any
one or more of the several funds. Employees are eligible for
participation in the Thrift Plan after completing one year of service.
In 1990, the Corporation established a Leveraged Employee Stock Ownership
Plan (LESOP). The LESOP was designed to pre-fund a portion of the
matching obligation under the terms of the Thrift Plan and to utilize tax
82
83
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
advantages afforded by the Internal Revenue Code.
In October 1991, the Board of Directors of the Corporation authorized the
termination of the LESOP subject to the approval of the Bankruptcy Court.
It is anticipated that the termination will be part of the Corporation's
plan of reorganization. Upon termination, any shares of common stock of
the Corporation remaining in the LESOP Trust account would be sold and
the proceeds paid to the holders of debentures issued under the LESOP.
Any unpaid balance due would become subject to the subordinate guarantee
of the Corporation and become a claim to be resolved as part of the
reorganization plan. Based on recently issued guidance from the American
Institute of Certified Public Accountants, it is anticipated the ultimate
termination will not result in any charges to earnings, but will result
in a reduction to capital of approximately $34.1 million based on a
closing stock price of $25 3/8 on January 31, 1994. As of December 31,
1993, the LESOP suspense account held 1,416,155 shares.
The participating subsidiaries ceased making contributions to the LESOP
for debt service payments but continue to contribute to the Thrift Plan
those amounts necessary to fulfill the matching obligations to
participants. Matching contributions to the Thrift Plan were $11.0
million, $13.2 million and $8.6 million in 1993, 1992, and 1991,
respectively. Thrift Plan expenses were $11.0 million, $13.2 million and
$17.9 million for 1993, 1992 and 1991, respectively. The difference
between matching contributions and expense for 1991 was attributable to
the additional expenses required under the now suspended LESOP.
10. DEBT OBLIGATIONS
The Corporation's filing for protection under the Bankruptcy Code
constituted an event of default under substantially all of its debt
agreements. Because payment of debt which existed at the filing date is
suspended by the Bankruptcy Code, substantially all of the Corporation's
debt, including short-term debt, has been classified as Liabilities
Subject to Chapter 11 Proceedings. In addition, payment of interest on
prepetition debt is suspended, and no interest expense on such debt has
been recorded since commencement of the bankruptcy proceedings.
Following the Chapter 11 filing, the Corporation received approval from
the Bankruptcy Court and the SEC, under the Public Utility Holding
Company Act of 1935, for debtor-in-possession financing (the DIP
Facility). The DIP Facility is for up to $100 million and includes the
availability of letters of credit of up to $50 million. The DIP Facility
was reduced by the Corporation from $275 million to $200 million on July
10, 1992 and was reduced to the current level effective June 17, 1993.
The Corporation has extended the DIP Facility to December 31, 1994.
Two borrowing options are available to the Corporation under the DIP
Facility. The Corporation may borrow at the agent's alternative
reference rate plus 1 percent or the Eurodollar rate plus 2 1/4 percent
(for either 1, 2 or 3 months). In addition to a commitment fee of 1/2 of
1 percent per annum on the average daily unused amount of the facility,
other fees have been paid to the lenders under the DIP Facility.
Columbia Transmission also maintains a DIP Facility solely for the
issuance of letters of credit for up to $25 million. Columbia
Transmission has extended its DIP Facility to December 31, 1995, to allow
for letters of credit with terms for the full calendar year of 1995.
11. DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The Corporation, effective December 31, 1992, adopted SFAS No. 107,
"Disclosures about Fair Value of Financial Instruments." The Statement
extends existing fair value disclosure practices by requiring all
entities to disclose the fair value of financial instruments, both assets
and liabilities, recognized and not recognized in
83
84
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
the Consolidated Balance Sheets, for which it is practicable to estimate
fair value. For purposes of this disclosure, the fair value of a
financial instrument is the amount at which the instrument could be
exchanged in a current transaction between willing parties, other than in
a forced or liquidation sale. Fair value may be based on quoted market
prices for the same or similar financial instruments, or on valuation
techniques such as the present value of estimated future cash flows using
a discount rate commensurate with the risks involved.
The uncertainties related to the outcome of the Corporation's Chapter 11
proceedings and the resulting effect upon the ultimate value of the
Corporation's financial assets and liabilities add significantly to the
uncertain nature of any estimate of fair value. The estimates of fair
value required under SFAS No. 107 require the application of broad
assumptions and estimates. Accordingly, any actual exchange of such
financial instruments could occur at values significantly different from
the amounts disclosed.
The following methods and assumptions were used to estimate the fair
value of each class of financial instruments for which it is practicable
to estimate that value:
As cash and temporary cash investments, current receivables, current
payables, and certain other short-term financial instruments are all
short-term in nature, their carrying amount approximates fair value. The
estimated fair values of the Corporation's other financial instruments
are reflected in the accompanying table.
Long-term investments
Long-term investments include escrowed proceeds from the sale of the
Canadian subsidiary (see Note 6B), which consist of hedged Canadian
Treasury bills ($25.4 million and $25.1 million for 1993 and 1992,
respectively). The Canadian Treasury bills are hedged with short-term
foreign currency contracts, so that the combined carrying amount of the
asset and related hedging instrument approximates fair value. Long-term
investments also include an income tax refund receivable with associated
interest at IRS rates ($31.2 million for 1993) whose carrying amount
approximates fair value. Also included are loans receivable ($12.8
million and $15.6 million for 1993 and 1992, respectively) whose
estimated fair values are based on the present value of estimated future
cash flows using an estimated rate for similar loans extended currently.
It is not practicable to estimate the fair value of long-term receivables
($144.4 million and $154.2 million for 1993 and 1992, respectively) for
the expected recovery by Columbia Transmission of certain gas purchase
liabilities for which the timing and amount of payments to be received
will be dependent on the outcome of the Chapter 11 proceedings. As
discussed in Note 2, the uncertainties related to these proceedings could
significantly influence the fair value of this financial instrument. The
financial instruments included in long-term investments are primarily
reflected in Investments and Other Assets in the Consolidated Balance
Sheets.
Liabilities subject to Chapter 11 proceedings
The estimated fair value of the Corporation's debentures and medium-term
notes is based on quoted market prices for those issues that are traded
on an exchange, and estimates provided by brokers for other issues.
However, quoted market prices and broker estimates inherently include
judgments concerning the outcome of the Corporation's and Columbia
Transmission's Chapter 11 proceedings.
Note 2 discusses the uncertainties related to these proceedings which
could significantly influence the fair value of these financial
instruments. It was not practicable to estimate the fair value of the
remaining long-term debt, which includes the Subordinated Guarantee of
the LESOP debt ($87.0 million) and miscellaneous debt of Columbia
Transmission ($1.4 million for 1993 and 1992), because no reliable
measurement methodology exists. Prior to filing its petition for
protection under Chapter 11 of the Bankruptcy Code, the Corporation
regularly issued commercial paper, bank notes and other short-term debt
instruments. The carrying amount of such securities ($892.6 million) is
included in Liabilities Subject to Chapter 11 Proceedings. Payment of
these obligations and any related interest is subject to approval by the
Bankruptcy Court. Although investors from time to time may buy and sell
these debt obligations, the terms of any such transactions are private
and not
84
85
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
disclosed to the Corporation. Because there can be no assurance as to
the ultimate timing and amount of principal and interest repayments of
these obligations, it is not practicable to determine their fair values.
The carrying amount of other Liabilities Subject to Chapter 11
Proceedings ($1,556.0 million and $1,595.4 million for 1993 and 1992,
respectively) primarily represents accounts payable, accrued liabilities
and other liabilities. As discussed in Note 2, these liabilities are
subject to adjustment at the direction of the Bankruptcy Court. In
addition, the timing of the ultimate payment of these liabilities, as
well as interest, if any, is also subject to determination by the
Bankruptcy Court. Accordingly, it is not practicable to determine the
fair value of these liabilities.
1993 1992
----------------------- -------------------
Carrying Fair Carrying Fair
At December 31 ($ in millions) Amount Value Amount Value
------------------------------------------------------------------------------------------------------------------
Long-term investments for which it is:
Practicable to estimate fair value 69.8 69.9 40.8 41.0
Not practicable to estimate fair value 144.4 - 154.2 -
Liabilities subject to Chapter 11 proceedings for which it is:
Practicable to estimate fair value
Long-term debt 1,390.8 1,557.5 1,390.8 1,373.6
Not practicable to estimate fair value
Long-term debt 88.4 - 88.4 -
Bank loans and commercial paper 892.6 - 892.6 -
Other 1,556.0 - 1,595.4 -
------------------------------------------------------------------------------------------------------------------
12. OTHER COMMITMENTS AND CONTINGENCIES
A. CAPITAL EXPENDITURES. Capital expenditures for 1994 are currently
estimated at $468 million. Of this amount, $91 million is for oil and
gas operations, $201 million for transmission operations, $152 million
for distribution operations and $24 million for other energy operations.
B. PRODUCER CONTRACT MATTERS. Columbia Transmission has rejected more than
4,800 natural gas purchase contracts which collectively made the
company's gas sales rate noncompetitive. Under Order 636, Columbia
Transmission will have a minimal merchant function, i.e., less than one
percent of total throughput. Customers' requirements will be met with
gas purchased under remaining and new contracts including 30- day spot
contracts as may be required. Rejection of additional contracts could
result in liabilities that could require future charges against earnings.
C. PARTNERSHIP PROJECTS. Columbia Gulf is a general partner in the
Trailblazer, Overthrust and Ozark partnerships. Since these partnerships
are nonrecourse, project-financed pipelines, firm shipper contracts were
assigned to banks (or in the case of Ozark to the Indenture Trustee) as
collateral for loans. Columbia Transmission and other shippers are
attempting to negotiate exit fees under Order 636 with the partnerships.
As a result of these negotiations and the current depressed demand for
the capacity on several of these pipelines, the realizability of these
investments is uncertain. Accordingly, a reserve of $5.4 million was
established in 1993. At December 31, 1993, Columbia Gulf's investment in
the partnerships amounted to $35.4 million, net of the valuation reserve
and before related deferred taxes.
D. OTHER LEGAL PROCEEDINGS. The Corporation and its subsidiaries have been
named as defendants in various legal
85
86
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
proceedings. In the opinion of management, the ultimate disposition of
these currently asserted claims will not have a material adverse impact
on the Corporation's consolidated financial position or results of
operations.
E. ASSETS UNDER LIEN. The loans under the debtor-in-possession financing
arrangement for the Corporation are given superpriority claim status
pursuant to Section 364(c) (1) of the Bankruptcy Code. Loans to the
Corporation are secured by either a first or second priority perfected
lien on, and security interest in, all property of the Corporation
including intercompany loans, other than the voting securities of the
Corporation's distribution subsidiaries and Columbia LNG. Columbia
Transmission's letter of credit facility is secured by either a first or
second priority perfected lien on, and security interest in, all property
of Columbia Transmission.
Substantially all of Columbia Transmission's properties have been pledged
to the Corporation as security for debt owed by Columbia Transmission to
the Corporation.
F. COVE POINT LNG TERMINAL. In 1991, the Corporation entered into a
conditional agreement for the sale of its remaining interest in Columbia
LNG to Shell LNG Company (Shell LNG), a subsidiary of Shell Oil Company.
On July 16, 1992, the Corporation was notified by Shell LNG that it would
not proceed with the interim purchase of 40.8 percent of the stock of
Columbia LNG. Shell LNG's notification terminated the agreements between
the Corporation and Shell LNG for the purchase of the remaining Columbia
LNG stock. Shell LNG currently owns 9.2 percent of Columbia LNG's
outstanding stock.
As previously reported, Columbia LNG has developed a new business plan to
reactivate the Cove Point facility. This plan anticipated a new peaking
and storage service by the end of 1994, as well as a terminalling service
for liquefied natural gas (LNG) received by tanker. An application with
the FERC to charge customers based upon individually negotiated market
rates was filed in February 1993. In accordance with the business plan
and in anticipation of the FERC filing, management concluded, in 1992,
that it was no longer appropriate for Columbia LNG to continue
application of SFAS No. 71 and regulatory assets were removed from
Columbia LNG's balance sheet resulting in an extraordinary charge of
$60.1 million pre-tax ($39.7 million after-tax) recorded in the third
quarter of 1992.
An open season, allowing potential customers to bid on the capacity of
all of the offered services, was held March 31, 1993 through April 14,
1993. Based on the results of the bids, which were not sufficient to
proceed with the project as it was originally proposed, Columbia LNG
restructured the offered services to more adequately address the service
needs of the potential customers. A second open season, offering
additional services, was held May 24, 1993 through June 2, 1993. This
open season resulted in sufficient bids to proceed with the peaking and
transportation services. The one bid received during the second open
season for baseload terminalling service was subsequently withdrawn. As
a result, Columbia LNG does not currently anticipate a baseload
terminalling service in the near future. As a consequence, Columbia LNG
recorded a writedown in the carrying value of its investment in the Cove
Point facility in the second quarter 1993 that reduced the Corporation's
income $37.9 million after-tax. This amount included estimated
dismantling costs for the offshore facilities of approximately $12
million after-tax. However, until such time as the offshore facilities
are transferred to the new partnership, as discussed below, Columbia LNG
plans to maintain the facilities for possible future imports and, at the
present time, has no plans to abandon or dismantle them. Besides the
writedown discussed above and the extraordinary charge discussed in the
preceding paragraph, Columbia LNG has incurred operating losses during
the prior three years which are not significant to the consolidated
financial results of the Corporation.
On October 28, 1993, as amended on January 27, 1994, PEPCO Enterprises,
Inc. (PEPCO), which is a wholly-owned subsidiary of Potomac Electric
Power Company, entered into an agreement to form a limited partnership.
The February 1993 filing with the FERC was withdrawn by Columbia LNG and
the Partnership, Cove Point LNG Limited Partnership (Cove Point LNG) that
will pursue the business plan discussed above, filed an
86
87
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
application with the FERC on November 3, 1993, seeking authorization to
acquire all of the existing plant and pipeline facilities owned by
Columbia LNG and for authorization to recommission the plant and
construct new facilities in order to provide peaking services beginning
in 1995. On the same day, Columbia LNG filed with the FERC for
authorization to abandon its facilities by transfer to Cove Point LNG and
to withdraw its February 26, 1993 filing. In addition to the FERC, this
transaction will require other governmental approvals. Bankruptcy Court
approval was received in January 1994.
After the receipt of necessary regulatory approvals, the PEPCO affiliates
will contribute up to $25 million in equity and loans for their half
interest in the partnership. At the same time, Columbia LNG will
transfer title to its existing plant and pipeline facilities to the
partnership and assign to the partnership the precedent agreements for
the services to be offered. Any cash requirements of the partnership
prior to the in-service date of the project which are in excess of $25
million will be provided by Columbia LNG up to a maximum of $7 million.
The cost of recommissioning the Cove Point facility and installing the
necessary liquefaction equipment is estimated to be approximately $27
million. Columbia LNG or an affiliate will operate the plant and
pipeline facilities for the partnership.
A number of intervenors filed with the FERC in regard to Columbia LNG's
plan for the Cove Point facility. While generally supportive of the plan
to reopen the facility, some of the intervenors questioned the use of the
individually negotiated market rates and requested the pass-through of
certain benefits from prior collections from Columbia Transmission.
The realization of the Corporation's remaining investment in Columbia LNG
of $10.1 million will be dependent upon successful implementation of the
partnership and related business plan.
G. OPERATING LEASES. Payments made in connection with operating leases are
charged to operation and maintenance expense as incurred. Such amounts
were $55.5 million in 1993, $57.9 million in 1992 and $57.9 million in
1991. Future minimum rental payments required under operating leases
that have initial or remaining noncancelable lease terms in excess of one
year are:
($ in millions)
------------------------------------------------------------------------------------------------------------------
1994 18.2
------------------------------------------------------------------------------------------------------------------
1995 18.4
------------------------------------------------------------------------------------------------------------------
1996 17.8
------------------------------------------------------------------------------------------------------------------
1997 14.1
------------------------------------------------------------------------------------------------------------------
1998 14.2
------------------------------------------------------------------------------------------------------------------
After 44.9
------------------------------------------------------------------------------------------------------------------
H. ENVIRONMENTAL MATTERS. The Corporation's subsidiaries are subject to
extensive federal, state and local laws and regulations relating to
environmental matters. These laws and regulations, which are constantly
changing, require expenditures for corrective action at various operating
facilities, waste disposal sites and former gas manufacturing sites for
conditions resulting from past practices that subsequently were
determined to be environmentally unsound.
Certain subsidiaries have received notice from the United States
Environmental Protection Agency (EPA) that
87
88
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
they are among several parties responsible under federal law for placing
wastes at Superfund sites and may be required to share in the cost of
remediation for these sites. However, considering known facts, existing
laws and possible insurance and rate recoveries, management does not
believe the identified Superfund matters will have a material adverse
effect on future annual income or on the Corporation's financial
position.
The transmission subsidiaries are continuing their comprehensive review
of compliance with existing environmental standards, including review of
past operational activities and identification of potential site
problems, through site reviews and formulation of remediation programs
where necessary. While the Corporation's transmission subsidiaries have
made progress in these ongoing self-assessment programs, because of the
thousands of miles of pipeline which they operate, the exceptionally
large number of sites at which they conduct or have conducted operations,
and the long period over which operations have been conducted, completion
of site screenings, characterizations and site-specific remediations will
cover a time frame of approximately 10 to 12 years.
A study for Columbia Transmission to quantify the scope of remediation
activities which will be undertaken in future years to address the issues
identified was recently concluded. The study, site investigations and
characterization efforts performed throughout 1993 resulted in total
accruals for the year of approximately $60 million for Columbia
Transmission. These and other minor adjustments bring Columbia
Transmission's recorded net liability to approximately $143.6 million at
December 31, 1993. This represents the lower end of the range of
reasonable outcomes with the upper end estimated to total approximately
$280 million based on information currently available.
As characterization and site-specific activities by Columbia Transmission
determine the nature and extent of contamination, if any, at its
operating facilities and as remediation plans are developed, additional
charges to earnings could occur. To the extent such plans require
approval of federal and/or state authorities, estimates are subject to
revision. Based on the limited data now available and various
assumptions as to characterization, management believes that annual
future expenditures for Columbia Transmission's site investigations,
characterization and remediation activities could be up to $20 million
per year over an approximate 10 to 12 year time frame. Earnings will
continue to be charged appropriately in advance of required expenditures.
As a result of site characterization studies at various locations, during
1993, Columbia Gulf recorded an additional accrual of $6.7 million for
environmental remediation. This accrual is for polychlorinated biphenyl
(PCB) and petroleum hydrocarbon cleanup at certain compressor station
sites and screenings for possible exposure at other locations. Columbia
Gulf anticipates completion of cleanup during 1994. At that time, costs
of remediation, if any, will be quantified and an additional accrual may
become necessary.
In 1992, Columbia Transmission received a subpoena and information
request (Request) from the EPA Region III regarding three major
environmental statutes: The Toxic Substances Control Act (TSCA), the
Resource Conservation and Recovery Act (RCRA) and the Comprehensive
Environmental Response Compensation and Liability Act (CERCLA). The
Request relates to Columbia Transmission's past and current environmental
practices. Since receipt of the Request, Columbia Transmission has
provided the EPA with various materials pursuant to the Request.
Columbia Transmission has continued to meet with the EPA to attempt to
resolve the subpoena issues and continues to work cooperatively with
environmental officials in the various states in which it operates. All
environmental agencies have been declared exempt from the Bar Date
established by the Bankruptcy Court for claims by creditors.
Columbia Transmission on January 28, 1994, received from EPA Region V an
Information Request pursuant to the RCRA. The agency requested Columbia
Transmission to submit information and knowledge relating to its
generation and management of natural gas pipeline condensate, used engine
oil and similar liquids in the state of Ohio. Columbia Transmission is in
the process of analyzing the information requested and will be discussing
this Information Request with EPA Region V.
88
89
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
At least one distribution subsidiary and some of the predecessor
companies of the distribution subsidiaries were, or may have been,
involved with the ownership and/or the operation of manufactured gas
plants. At the present time management is aware of twelve such sites.
The distribution subsidiaries are conducting investigations at five sites
that date back to the mid-1800s. These plants heated coal tar in a
low-oxygen atmosphere to manufacture low-cost gas for areas where natural
gas was not generally available. The process created residues such as
coal tar which were typically stored on site prior to being sold for
commercial use. However, when the plants stopped operation the remaining
residue material was in some cases simply buried on the plant sites. As
time passed, other uses were made of the plant sites and in some cases
their identity as a manufactured gas plant was lost. To the extent site
investigations have been completed, remediation plans developed, and any
responsibility for remedial action established, the appropriate liability
has been recorded. The environmental assessment and evaluation process
will continue over the next three to five years. Environmental
investigations indicate that remedial action may be required.
Investigations will be conducted at a number of the other sites in the
near future. The following discusses the status of certain sites:
In 1985, CPA was cited by the Pennsylvania Department of Environmental
Resources for coal tar residues on the bottom of a creek bed in York,
Pennsylvania. The area was adjacent to the site of a manufactured gas
plant operated from 1885 to the early 1950s by a predecessor company, the
York County Gas Company, which was purchased in 1968. The site has been
under investigation by CPA's consultants to determine the extent of any
underground contamination and to propose various remedial measures that
can be used to eliminate the release to the creek or remediate the
premises. The current costs of the investigation are being recovered in
rates. Site remediation costs have been estimated at $4.2 million, which
has been recorded as a liability and a corresponding regulatory asset.
CPA expects to continue to recover these costs in rates based upon orders
received in previous rate cases. However, the ability to recover these
costs is subject to (1) the results of each future rate case during the
expenditure period or (2) the outcome of a settlement proposal to treat
these expenditures as a cost of removal by charging them to the reserve
for depreciation and recover them over a five-year period. Remediation
work is expected to start in 1994.
Penn Fuel Gas, Inc. (Penn Fuel) advised CPA that a site in Bellefonte,
Pennsylvania, sold to Penn Fuel by Central Pennsylvania Gas Company in
1960 was the location of a manufactured gas plant until the mid-1950s.
The plant's equipment was disassembled at the time Penn Fuel acquired the
property. The old processing building is still used as a warehouse by
Penn Fuel. In 1966, CPA acquired substantially all of Central
Pennsylvania Gas Company's assets and liabilities.
CPA has agreed to share with Penn Fuel, the costs of investigating the
site for environmental contamination and up to $300,000 of the
investigation costs. A regulatory asset and offsetting liability was
recorded by CPA in March 1993. There is no agreement, nor is there any
admission by either CPA or Penn Fuel, regarding liability, if any, for
abatement and/or remediation of the site. It is expected that the
positions and potential responsibility of each party will become clearer
as the investigation proceeds.
In January 1993, the owners of the Patio Plaza Apartments, BMI Apartment
Associates (a partnership), contacted COS about possible soil
contamination of a site in Portsmouth, Virginia, on which the Portsmouth
Gas Company operated a manufactured gas plant from 1854 to 1951. The
Portsmouth Gas Company sold this site to the Portsmouth Redevelopment and
Housing Authority in 1960. The Portsmouth Gas Company was acquired by
Commonwealth Natural Resources, Inc. and subsequently merged into COS in
1981. The Redevelopment Authority subsequently razed the plant and sold
the vacant land. Apartments and houses were built on the property and
the current owners of some of the apartments reported possible soil
contamination to the Virginia Water Quality Control Board. COS notified
the EPA regarding the engineering reports provided to it by the owners.
On March 25, 1993, COS and the Portsmouth Redevelopment and Housing
Authority jointly filed suit in U.S. District Court, Eastern District of
Virginia at Norfolk, Virginia, against the current and former owners of
the apartments. The suit sought a declaration that those other parties
are liable for the site and requested access to the property for testing
which had been denied by the current owners. On June 14, 1993, the Court
ordered
89
90
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
that COS be permitted access to perform necessary testing of soil and air
that resulted in a determination that there was no imminent danger to the
residents. Subsequently, the Court granted a stay of all legal
proceedings until May 16, 1994 to permit COS to conduct further site
testing to determine the extent of any contamination and to recommend
corrective measures. Most of that testing was completed in November and
December 1993, and the results are anticipated in early 1994. On
February 14, 1994, the judge appointed a magistrate to oversee settlement
of the suit.
COS incurred legal and engineering consultant expenses that reached
approximately $400,000 in 1993. Additional costs are currently
anticipated to reach $400,000 in 1994 and accordingly a regulatory asset
has been established for $800,000 and the appropriate liability recorded.
Other work at this site is anticipated but it is not possible at this
time to estimate the costs. Permission was granted by the VSCC to defer
the costs of this project as a regulatory asset, subject to recovery in
the next rate case.
In February 1993, COS reported to the Virginia Department of
Environmental Quality (VaDEQ) a potential soil contamination below a
retaining wall at the Petersburg, Virginia Service Center . The VaDEQ has
ordered COS to prepare a preliminary site assessment related to the
report. In early June 1993, COS contractors performed testing and
prepared the preliminary site assessment which was submitted to VaDEQ in
July 1993. Additional testing on another area of leakage was conducted
in September 1993 with results reported to the VaDEQ in late October
1993. COS is currently completing the removal of contaminated material
from an old underground tank on the property which was contributing to
the leakage problem. Additional corrective work may be performed in 1994
as a result of further testing that will be conducted.
COS has incurred legal and engineering consultant expenses that reached
approximately $170,000 by the end of 1993. At this time, it is not
possible to estimate the costs of corrective action or of further work
the VaDEQ might require. However, additional consultant costs are
estimated to be $280,000 in 1994. Accordingly, a regulatory asset of
$450,000 has been established and the liability recorded. Permission was
granted by the VSCC to defer the costs of this project as a regulatory
asset subject to recovery in the next rate case.
A former manufactured gas plant site in Lynchburg, Virginia was included
with the assets of the Lynchburg Gas Company when it was merged into COS
in 1989. A liability of $600,000 has been recorded for the removal of
certain remaining structures from the manufactured gas plant and clean up
of debris at the site. The VSCC has granted COS permission to defer the
costs associated with this work and any other remediation related to the
site for review and potential recovery in rates at a later time.
A former manufactured gas plant site in Hagerstown, Maryland was included
with other assets of the Hagerstown Gas Company acquired by CMD in 1969.
This plant operated between 1891 and 1949. The site, at the location of
the CMD service center in Hagerstown was reported to the EPA by the state
and has been assigned medium priority status by the EPA for future
investigation. No investigations have been conducted by the state of
Maryland or the EPA at this site and, therefore, it is not possible at
this time to estimate the cost of remediation activities, if any.
To the extent the above-mentioned site investigations have been
completed, remediation plans developed, and any Distribution
responsibility for remedial action established, the appropriate liability
has been recorded. As additional investigations are completed and
remediation costs become probable, the appropriate liability will be
recorded. As of December 31, 1993, the distribution subsidiaries
recorded net liabilities of $5.9 million. Management anticipates
recovery of remediation costs through normal rate proceedings.
The eventual total cost of full future environmental compliance for the
Columbia Gas System is difficult to estimate due to, among other things:
(1) the possibility of as yet unknown contamination, (2) the possible
effect of future legislation and new environmental agency rules, (3) the
possibility of future litigation, (4) the possibility of future
designations as a potential responsible party by the EPA and the
difficulty of determining liability, if any, in proportion to other
responsible parties, (5) possible insurance and rate recoveries, and (6)
the effect of possible technological changes relating to future
remediation. However, reserves have been
90
91
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
established based on information currently available which resulted in a
total recorded net liability of $156.1 million for the Columbia Gas
System at December 31, 1993, which includes the low end of a range for
certain expenditures for the transmission segment previously discussed.
As new issues are identified, appropriate additional liabilities may have
to be recorded.
It is management's continued intent to address environmental issues in
cooperation with regulatory authorities in such a manner as to achieve
mutually acceptable compliance plans. However, there can be no assurance
that fines and penalties will not be incurred.
Management expects most environmental assessment and remediation costs to
be recoverable through rates. Although significant charges to earnings
could be required prior to rate recovery, management does not believe
that environmental expenditures will have a material adverse effect on
the Corporation's financial position, based on known facts, existing laws
and regulations and the period over which expenditures are required.
91
92
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
13. INTEREST INCOME AND OTHER, NET
Year Ended December 31 ($ in millions) 1993 1992 1991
-------------------------------------------------------------------------------------------------------
Interest income 9.8 13.2 17.0
Gains on sale of interests in subsidiaries - - 21.4
Impairment of other investments (10.1) (3.6) (14.5)
Income from equity investments 4.8 9.3 5.5
Miscellaneous 2.8 1.6 3.0
-------------------------------------------------------------------------------------------------------
TOTAL 7.3 20.5 32.4
-------------------------------------------------------------------------------------------------------
14. INTEREST EXPENSE AND RELATED CHARGES
Year Ended December 31 ($ in millions) 1993 1992 1991
-------------------------------------------------------------------------------------------------------
Interest on debt 0.2 0.3 108.3
Interest on DIP financing 2.9 4.5 4.1
Interest on rate refunds 8.4 3.5 8.4
Interest on prior years' taxes 74.5 - 7.7
Other interest charges 15.5 5.4 11.5
Allowance for borrowed funds used
and interest during construction - - (2.6)
-------------------------------------------------------------------------------------------------------
TOTAL 101.5 13.7 137.4
-------------------------------------------------------------------------------------------------------
15. CHANGES IN COMPONENTS OF WORKING CAPITAL
(excludes cash and temporary cash investments, short-term debt and
current maturities of long-term debt)
Year Ended December 31 ($ in millions) 1993 1992 1991
-------------------------------------------------------------------------------------------------------
Accounts receivable, net 0.1 114.8 (60.8)
Gas inventory 140.2 41.7 63.1
Accounts and drafts payable (47.3) 43.3 (120.9)
Accrued taxes (14.6) 8.3 70.9
Estimated rate refunds 95.5 114.4 9.5
Estimated supplier obligations 145.9 (3.8) 67.6
Deferred income taxes (19.7) (1.8) (26.5)
Miscellaneous 92.7 (35.5) 75.7
-------------------------------------------------------------------------------------------------------
Change in working capital 392.8 281.4 78.6
Reclassifications (164.7) (189.9) 96.6
-------------------------------------------------------------------------------------------------------
NET CHANGE IN WORKING CAPITAL 228.1 91.5 175.2
-------------------------------------------------------------------------------------------------------
92
93
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
16. BUSINESS SEGMENT INFORMATION
The following tables provide information concerning the Corporation's
major business segments. Revenues include intersegment sales to
affiliated subsidiaries, which are eliminated when consolidated.
Affiliated sales are recognized on the basis of prevailing market or
regulated prices. Operating income is derived from revenues and expenses
directly associated with each segment. Identifiable assets include only
those attributable to the operations of each segment.
($ in millions) 1993 1992 1991
-------------------------------------------------------------------------------------------------------
REVENUES
Oil and gas -Unaffiliated 181.2 184.9 201.2
-Intersegment 41.0 13.8 13.6
-------------------------------------------------------------------------------------------------------
TOTAL 222.2 198.7 214.8
-------------------------------------------------------------------------------------------------------
Transmission -Unaffiliated 1,142.8 954.6 727.3
-Intersegment 642.9 532.9 402.2
-------------------------------------------------------------------------------------------------------
TOTAL 1,785.7 1,487.5 1,129.5
-------------------------------------------------------------------------------------------------------
Distribution -Unaffiliated 1,830.7 1,647.6 1,533.5
-Intersegment - - -
-------------------------------------------------------------------------------------------------------
TOTAL 1,830.7 1,647.6 1,533.5
-------------------------------------------------------------------------------------------------------
Other energy -Unaffiliated 236.5 134.9 114.8
-Intersegment 69.9 68.9 81.7
-------------------------------------------------------------------------------------------------------
TOTAL 306.4 203.8 196.5
-------------------------------------------------------------------------------------------------------
Adjustments -Unaffiliated - - -
and eliminations -Intersegment (753.8) (615.6) (497.5)
-------------------------------------------------------------------------------------------------------
TOTAL (753.8) (615.6) (497.5)
-------------------------------------------------------------------------------------------------------
CONSOLIDATED 3,391.2 2,922.0 2,576.8
-------------------------------------------------------------------------------------------------------
93
94
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
($ in millions) 1993 1992 1991
-------------------------------------------------------------------------------------------------------
OPERATING INCOME (LOSS)
Oil and gas 53.6 (101.2) (4.5)
Transmission 178.7 129.9 (1,192.2)
Distribution 146.4 137.7 114.9
Other energy 1.7 6.8 4.9
Corporate (7.0) (10.3) (9.5)
-------------------------------------------------------------------------------------------------------
CONSOLIDATED 373.4 162.9 (1,086.4)
-------------------------------------------------------------------------------------------------------
DEPRECIATION & DEPLETION
Oil and gas 73.8 210.0 130.1
Transmission 97.8 95.6 90.4
Distribution 62.3 57.6 60.5
Other energy 5.9 4.9 4.0
-------------------------------------------------------------------------------------------------------
CONSOLIDATED 239.8 368.1 285.0
-------------------------------------------------------------------------------------------------------
IDENTIFIABLE ASSETS
Oil and gas 732.0 734.9 871.8
Transmission 4,156.6 3,897.7 3,544.9
Distribution 2,065.5 1,967.3 1,868.2
Other energy 128.6 124.1 119.2
Adjustments and eliminations (376.3) (388.6) (344.5)
Corporate and unallocated 251.5 170.5 272.6
-------------------------------------------------------------------------------------------------------
CONSOLIDATED 6,957.9 6,505.9 6,332.2
-------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES
Oil and gas 95.1 70.8 120.8
Transmission 137.2 114.2 152.9
Distribution 117.8 99.7 98.0
Other energy 11.2 15.0 10.2
-------------------------------------------------------------------------------------------------------
CONSOLIDATED 361.3 299.7 381.9
-------------------------------------------------------------------------------------------------------
94
95
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
17. QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly financial data does not always reveal the trend of the System's
business operations due to bankruptcy matters, nonrecurring items and
seasonal weather patterns which affect earnings and related components of
operating revenues and expenses.
First Second Third Fourth
($ in millions except per share data) Quarter Quarter Quarter Quarter
----------------------------------------------------------------------------------------------------
1993
Operating Revenues 1,222.6 592.9 565.5 1,010.2
Operating Income 223.1 1.5 2.5 146.3
Net Income (Loss) 139.8 (a) (2.6) (b) (54.4) (c) 69.4 (d)
Per Share Amounts
Earnings (Loss) on Common Stock 2.77 (0.06) (1.07) 1.37
----------------------------------------------------------------------------------------------------
1992
Operating Revenues 1,032.2 522.1 432.2 935.5
Operating Income (Loss) 21.1 54.5 (63.0) 150.3
Income (Loss) before Extraordinary
Item 10.8 (e) 30.7 (f) (38.4) (g) 87.8 (h)
Extraordinary Item - - (39.7) -
Net Income (Loss) 10.8 30.7 (78.1) 87.8
Per Share Amounts
Earnings (Loss) before Extraordinary
Item 0.21 0.61 (0.76) 1.73
Extraordinary Item - - (0.78) -
Earnings (Loss) on Common Stock 0.21 0.61 (1.54) 1.73
----------------------------------------------------------------------------------------------------
(a) Includes an increase in net income of $13.2 million for the reversal
of rate reserves to reflect the outcome of rate cases related to the
transmission segment. The effect of not recording interest expense
on prepetition debt improved net income $38.2 million.
(b) Includes a decrease in net income of $37.9 million to record a
writedown in the investment in the Cove Point LNG facility and a
decrease in net income of $7.4 million to record the estimated loss
on the sale of storage inventory. The effect of not recording
interest expense on prepetition debt improved net income $36.0
million.
(c) Includes a decrease in net income of $40.4 million to record the
effect of a preliminary settlement with the IRS, a decrease in net
income of $13.0 million to record a liability for future
environmental remediation costs, a decrease in net income of $9.8
million to reflect the effect of the higher federal corporate tax
rate and a decrease in net income of $9.8 million for several
smaller unusual items. The effect of not recording interest expense
on prepetition debt improved net income $33.8 million.
(d) Includes an increase in net income of $13.5 million for gas
inventory charges collected from customers and an increase in net
income of $12.8 million for the WACOG surcharge collected from
customers, partially offset by a decrease in net income of $12.6
million for an adjustment to interest income for pipeline direct
billings. The effect of not recording interest expense on
prepetition debt improved net income $30.1 million.
(e) Includes a decrease in net income of $83.4 million to record a
writedown in the carrying value of U.S. oil and gas properties. The
effect of not recording interest expense on prepetition debt
improved net income $36.8 million.
(f) The effect of not recording interest expense on prepetition debt
improved net income $36.0 million.
(g) Includes a decrease in net income of $39.2 million to record a
liability for future environmental remediation costs and a decrease
in net income of $24.2 million to record a provision for gas supply
charges. The effect of not recording interest expense on
prepetition debt improved net income $36.6 million.
(h) Includes an increase in net income of $13.1 million for gas
inventory charges collected from customers. The effect of not
recording interest expense on prepetition debt improved net income
$39.1 million.
95
96
18. OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
INTRODUCTION. Reserve information contained in the following tables for
the U.S. properties is management's estimate, which was reviewed by the
independent consulting firm of Ryder Scott Company Petroleum Engineers.
Reserves are reported as net working interest. Gross revenues are
reported after deduction of royalty interest payments.
The Corporation sold its Canadian subsidiary to Anderson Exploration Ltd.
of Calgary effective December 31, 1991. In 1991 the oil and gas operations
of the Canadian subsidiary resulted in a $24.4 million loss. Accordingly,
the reserve and other information for the Canadian properties are not
included in the tables for 1991, 1992 and 1993.
CAPITALIZED COSTS
-----------------------------------------------------------------------------
($ in millions) 1993 1992 1991
-----------------------------------------------------------------------------
CAPITALIZED COSTS AT YEAR END
Proved properties 1,129.6 1,111.5 1,086.9
Unproved properties (a) 79.1 78.9 80.7
-----------------------------------------------------------------------------
Total capitalized costs 1,208.7 1,190.4 1,167.6
Accumulated depletion (600.0) (602.1) (441.3)
-----------------------------------------------------------------------------
NET CAPITALIZED COSTS 608.7 588.3 726.3
-----------------------------------------------------------------------------
COSTS CAPITALIZED DURING YEAR
Acquisition
Proved properties - 0.2 -
Unproved properties 7.1 4.6 6.4
Exploration 17.5 25.8 32.8
Development 70.1 39.7 62.9
-----------------------------------------------------------------------------
COSTS CAPITALIZED 94.7 70.3 102.1
-----------------------------------------------------------------------------
(a) Represents expenditures associated with properties on which
evaluations have not been completed.
HISTORICAL RESULTS
OF OPERATIONS
-----------------------------------------------------------------------------
($ in millions) 1993 1992 1991
-----------------------------------------------------------------------------
Gross revenues
Unaffiliated 181.7 183.9 181.8
Affiliated 40.9 13.2 14.1
Production costs 50.6 50.5 41.6
Depletion 73.5 209.4 (a) 82.1
Income tax expense 34.5 (25.0) 22.8
-----------------------------------------------------------------------------
RESULTS OF OPERATIONS 64.0 (37.8) 49.4
-----------------------------------------------------------------------------
Results of operations for producing activities exclude administrative and
general costs, corporate overhead and interest expense.
Income tax expense is expressed at statutory rates less Section 29
credits.
(a) Includes writedown of the carrying value of $126.4 million for 1992.
96
97
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
OTHER OIL AND GAS PRODUCTION DATA
-----------------------------------------------------------------------------
1993 1992 1991
-----------------------------------------------------------------------------
Average sales price per Mcf of gas ($) 2.28 2.02 1.88
Average sales price per barrel of oil and
other liquids ($) 16.17 18.20 22.18
Production (lifting) cost per dollar of
gross revenue ($) 0.23 0.26 0.21
Depletion rate per dollar of
gross revenue ($) 0.33 0.42 0.42
-----------------------------------------------------------------------------
RESERVE QUANTITY INFORMATION
-----------------------------------------------------------------------------
Oil and Other
Gas Liquids
Proved Reserves (Bcf) (000 Bbls)
-----------------------------------------------------------------------------
Reserves as of December 31, 1990 812.5 14,741
Revisions of previous estimate 14.2 (854)
Extensions, discoveries and
other additions 62.7 4,514
Production (70.1) (2,833)
Sale of minerals-in-place (11.2) -
-----------------------------------------------------------------------------
Reserves as of December 31, 1991 808.1 15,568
Revisions of previous estimate (9.1) (946)
Extensions, discoveries and other
additions 51.3 3,089
Production (69.2) (3,061)
Sale of minerals-in-place (1.6) -
-----------------------------------------------------------------------------
Reserves as of December 31, 1992 779.5 14,650
Revisions of previous estimate (60.1) (589)
Extensions, discoveries and
other additions 52.4 2,334
Production (71.5) (3,603)
Sale of minerals-in-place (3.3) -
-----------------------------------------------------------------------------
RESERVES AS OF DECEMBER 31, 1993 697.0 12,792
-----------------------------------------------------------------------------
Proved developed reserves as of December 31,
1991 697.7 13,338
1992 664.4 13,143
1993 573.7 10,793
-----------------------------------------------------------------------------
97
98
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
-----------------------------------------------------------------------------
($ in millions) 1993 1992 1991
-----------------------------------------------------------------------------
Future cash inflows 2,206.4 2,568.9 2,152.3
Future production costs (508.0) (562.3) (511.9)
Future development costs (172.0) (162.9) (157.8)
Future income tax expense (463.0) (546.4) (411.6)
-----------------------------------------------------------------------------
Future net cash flows 1,063.4 1,297.3 1,071.0
Less 10% discount 512.0 636.2 504.0
-----------------------------------------------------------------------------
STANDARDIZED MEASURE OF
DISCOUNTED FUTURE
NET CASH FLOWS 551.4 661.1 567.0
-----------------------------------------------------------------------------
Future cash inflows are computed by applying year-end prices to estimated
future production of proved oil and gas reserves. Future expenditures
(based on year-end costs) represent those costs to be incurred in
developing and producing the reserves. Discounted future net cash flows
are derived by applying a 10% discount rate, as required by the Financial
Accounting Standards Board, to the future net cash flows. This data is
not intended to reflect the actual economic value of the Corporation's
oil and gas producing properties or the true present value of estimated
future cash flows since many arbitrary assumptions are used. The data
does provide a means of comparison among companies through the use of
standardized measurement techniques.
98
99
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
A reconciliation of the components resulting in changes in the
standardized measure of discounted cash flows attributable to proved oil
and gas reserves for the three years ending December 31, 1993, follows:
------------------------------------------------------------------------------------------------
($ in millions) 1993 1992 1991
------------------------------------------------------------------------------------------------
Beginning of year 661.1 567.0 669.7
------------------------------------------------------------------------------------------------
Oil and gas sales,
net of production
costs (172.0) (146.6) (154.3)
Net changes in prices
and production costs (56.5) 210.4 (140.0)
Change in future
development costs (9.2) (5.1) 7.6
Extensions, discoveries
and other additions,
net of related costs 66.9 81.0 84.4
Revisions of previous
estimates, net of
related costs (71.1) (18.0) 8.9
Sale of reserves (4.4) (2.4) (15.8)
Accretion of discount 92.4 76.9 93.5
Net change in income
taxes 36.8 (61.3) 64.4
Timing of production
and other changes 7.4 (40.8) (51.4)
------------------------------------------------------------------------------------------------
END OF YEAR 551.4 661.1 567.0
------------------------------------------------------------------------------------------------
The estimated discounted future net cash flows decreased during 1993
primarily due to net changes in prices and production costs and revisions
to the economic feasibility of producing certain wells. The standardized
measure of the Corporation's oil and gas properties can be influenced by
affiliated and unaffiliated pipeline transportation rate design (which
continues to be evaluated by the FERC).
99
100
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Schedule I
----------
Page 1 of 2
MARKETABLE SECURITIES - OTHER INVESTMENTS
The Columbia Gas System, Inc. and Subsidiaries
December 31, 1993
($ in Millions)
Amount at
Market which Carried
Description* Principal Amount Cost Value** in Balance Sheet**
- ------------ ---------------- ---- ------- ------------------
U. S. Government Securities 291.0 291.8 291.8 291.8
U. S. Government
Agency Securities 115.0 114.9 114.9 114.9
Foreign Banks 141.2 140.9 140.9 140.9
Other Foreign 152.0 151.1 151.1 151.1
Industrial 375.8 374.2 374.2 374.2
Insurance 15.0 14.9 14.9 14.9
Commercial Paper Supported
by Letters of Credit 136.0 135.4 135.4 135.4
Securities Dealers 65.0 64.7 64.7 64.7
U. S. Banks 48.0 47.8 47.8 47.8
--------
Sub-total of Marketable Securities 1,335.7
Cash 4.7
--------
Total Cash and Temporary Cash Investments in Consolidated Balance Sheet 1,340.4
========
* The short-term investment portfolio consists of numerous securities with
similar market characteristics such as credit quality, maturity and
marketability. These include bills, notes and bonds issued by the U.S.
Government or its agencies (either purchased directly for the System or
through repurchase agreements) and money market instruments issued by
foreign and domestic corporations. Such instruments include commercial
paper and bank certificates of deposit.
** As these securities are short-term in nature, their carrying amount
approximates market value.
100
101
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Schedule I
----------
Page 2 of 2
MARKETABLE SECURITIES - OTHER INVESTMENTS
The Columbia Gas System, Inc. and Subsidiaries
December 31, 1992
($ in Millions)
Amount at
Market which Carried
Description* Principal Amount Cost Value** in Balance Sheet**
- ------------ ---------------- ---- ------- ------------------
U. S. Government Securities 99.7 99.7 99.7 99.7
U. S. Government
Agency Securities 97.5 96.8 96.8 96.8
Foreign Banks 120.0 119.0 119.0 119.0
Other Foreign 60.0 59.6 59.6 59.6
Industrial 105.0 104.2 104.2 104.2
Insurance 83.0 82.6 82.6 82.6
Commercial Paper Supported
by Letters of Credit 67.0 66.6 66.6 66.6
Securities Dealers 45.0 44.8 44.8 44.8
U. S. Banks 15.0 14.9 14.9 14.9
Other 120.0 119.4 119.4 119.4
------
Sub-total of Marketable Securities 807.6
Cash 13.0
------
Total Cash and Temporary Cash
Investments in Consolidated
Balance Sheet 820.6
======
* The short-term investment portfolio consists of numerous securities with
similar market characteristics such as credit quality, maturity and
marketability. These include bills, notes and bonds issued by the U.S.
Government or its agencies (either purchased directly for the System or
through repurchase agreements) and money market instruments issued by
foreign and domestic corporations. Such instruments include commercial
paper and bank certificates of deposit.
** As these securities are short-term in nature, their carrying amount
approximates market value.
101
102
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
PROPERTY, PLANT AND EQUIPMENT Schedule V
The Columbia Gas System, Inc. and Subsidiaries ----------
Year Ended December 31, 1993 Page 1 of 3
($ in Millions)
Beginning Additions Other Ending
Balance At Cost Retirements Changes Balance
--------- --------- ----------- ------- -------
Oil and Gas
United States Cost Center 1,190.4 94.7 71.0 (5.4) (a) 1,208.7
Other General Plant 4.2 0.4 - (0.1) 4.5
--------- --------- --------- --------- ---------
Total 1,194.6 95.1 71.0 (5.5) 1,213.2
--------- --------- --------- --------- ---------
Transmission
Transmission 2,974.0 99.1 23.2 (0.1) 3,049.8
Storage 808.3 22.4 1.1 3.9 (b) 833.5
Other 390.6 15.7 13.6 - 392.7
--------- --------- --------- --------- ---------
Total 4,172.9 137.2 37.9 3.8 4,276.0
--------- --------- --------- --------- ---------
Distribution
Distribution 1,752.8 114.2 7.1 (0.2) 1,859.7
Other 93.8 3.6 3.3 (0.1) 94.0
--------- --------- --------- --------- ---------
Total 1,846.6 117.8 10.4 (0.3) 1,953.7
--------- --------- --------- --------- ---------
Other Energy
Propane 37.3 2.8 0.4 - 39.7
Other 54.7 1.6 (c) 0.2 (0.2) 55.9
--------- --------- --------- --------- ---------
Total 92.0 4.4 0.6 (0.2) 95.6
--------- --------- --------- --------- ---------
Total Property, Plant and
Equipment 7,306.1 354.5 119.9 (2.2) 7,538.5
========= ========= ========= ========= =========
(a) Primarily reflects well sales by Columbia Natural Resources, Inc. ($5.5
million).
(b) Primarily reflects Columbia Transmission's transfer of 1.3 Bcf from
current gas inventory.
(c) Excludes capital expenditures related to "Investments and Other Assets"
($6.8 million).
NOTE:Construction work in progress for Gas Utility Plant was $56.7 million as
of December 31, 1993.
102
103
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
PROPERTY, PLANT AND EQUIPMENT Schedule V
The Columbia Gas System, Inc. and Subsidiaries ----------
Year Ended December 31, 1992 Page 2 of 3
($ in Millions)
Beginning Additions Other Ending
Balance At Cost Retirements Changes Balance
--------- --------- ----------- ------- -------
Oil and Gas
United States Cost Center 1,167.6 70.3 48.7 1.2 1,190.4
Other General Plant 17.7 0.5 0.7 (13.3) 4.2
--------- --------- --------- --------- ---------
Total 1,185.3 70.8 49.4 (12.1) (a) 1,194.6
--------- --------- --------- --------- ---------
Transmission
Transmission 2,898.2 86.8 10.7 (0.3) 2,974.0
Storage 813.8 25.3 1.2 (29.6) (c) 808.3
Other 393.7 2.1 2.8 (2.4) 390.6
--------- --------- --------- --------- ---------
Total 4,105.7 114.2 14.7 (32.3) 4,172.9
--------- --------- --------- --------- ---------
Distribution
Distribution 1,661.7 95.0 7.2 3.3 (a) 1,752.8
Other 91.0 4.7 2.7 0.8 93.8
--------- --------- --------- --------- ---------
Total 1,752.7 99.7 9.9 4.1 1,846.6
--------- --------- --------- --------- ---------
Other Energy
Propane 35.2 2.5 0.6 0.2 37.3
Other 50.4 6.4 (b) 0.1 (2.0) 54.7
--------- --------- --------- --------- ---------
Total 85.6 8.9 0.7 (1.8) 92.0
--------- --------- --------- --------- ---------
Total Property, Plant and
Equipment 7,129.3 293.6 74.7 (42.1) 7,306.1
========= ========= ========= ========= =========
(a) Primarily reflects the net transfer of assets from Inland Gas Company (Oil
and Gas - $5.5 million) to Columbia Gas of Kentucky, Inc. (Distribution
$5.5 million), and sales of assets by Columbia Natural Resources, Inc.
(Oil and Gas - $4.9 million).
(b) Excludes capital expenditures related to "Investments and Other Assets"
($6.1 million).
(c) Primarily reflects Columbia Transmission's transfer of
9.7 Bcf of gas to current gas inventory.
NOTE:Construction work in progress for Gas Utility Plant was $55.9 million as
of December 31, 1992.
103
104
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
PROPERTY, PLANT AND EQUIPMENT Schedule V
The Columbia Gas System, Inc. and Subsidiaries ----------
Year Ended December 31, 1991 Page 3 of 3
($ in Millions)
Beginning Additions Other Ending
Balance At Cost Retirements Changes Balance
--------- --------- ----------- ------- -------
Oil and Gas
United States Cost Center 1,130.7 102.1 54.5 (10.7) (a) 1,167.6
Canadian Cost Center 260.2 16.7 - (276.9) (b,c) -
Other General Plant 5.2 2.0 2.5 13.0 (c,d) 17.7
--------- --------- --------- --------- -------
Total 1,396.1 120.8 57.0 (274.6) 1,185.3
--------- --------- --------- --------- -------
Transmission
Transmission 2,777.8 130.8 10.5 0.1 2,898.2
Storage 810.0 4.4 0.6 - 813.8
LNG - Cove Point 202.2 - - (202.2) (e) -
Other 392.9 17.7 14.9 (2.0) 393.7
--------- --------- --------- --------- --------
Total 4,182.9 152.9 26.0 (204.1) 4,105.7
--------- --------- --------- --------- --------
Distribution
Distribution 1,640.2 92.6 7.4 (63.7) (d,f) 1,661.7
Other 102.6 5.4 2.4 (14.6) (d,f) 91.0
--------- --------- --------- --------- -------
Total 1,742.8 98.0 9.8 (78.3) 1,752.7
--------- --------- --------- --------- -------
Other Energy
Propane 34.6 1.7 1.1 - 35.2
Other 48.6 3.5 (g) 1.7 - 50.4
--------- --------- --------- --------- -------
Total 83.2 5.2 2.8 - 85.6
--------- --------- --------- --------- -------
Total Property, Plant and
Equipment 7,405.0 376.9 95.6 (557.0) 7,129.3
========= ========= ========= ========= ========
(a) Reflects sales of assets by Columbia Natural Resources, Inc.
(b) Includes foreign currency translation adjustment applicable to Canadian
property ($1.1 million).
(c) Includes the sale of Columbia Gas Development of Canada Ltd. in a
transaction completed in January 1992, effective December 31, 1991.
(Canadian Cost Center - $276.5 million and Other General Plant - $1.8
million).
(d) Includes reclassification of certain Inland Gas Company assets from
Distribution properties (Distribution - $7.7 million and Other - $7.0
million) to Oil and Gas properties (Other General Plant $14.7 million).
(e) Reflects the deconsolidation of Columbia LNG Corporation, now recorded as
"Investment in Columbia LNG Corporation".
(f) Includes the sale of Columbia Gas of New York, Inc. in a transaction
completed in April 1991 (Distribution - $55.4 million and Other - $5.6
million).
(g) Excludes capital expenditures related to "Investments and Other Assets"
($5.1 million).
NOTE:Construction work in progress for Gas Utility Plant was $52.1 million as
of December 31, 1991.
104
105
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
ACCUMULATED DEPRECIATION AND DEPLETION OF PROPERTY,
PLANT AND EQUIPMENT Schedule VI
The Columbia Gas System, Inc. and Subsidiaries -----------
Year Ended December 31, 1993 Page 1 of 3
($ in Millions)
Charged to
------------------
Beginning Other Other Ending
Balance Income Accounts Retirements Changes Balance
--------- ------ -------- ----------- ------- -------
Oil and Gas
United States Cost Center 602.1 73.5 - 71.0 (4.6) 600.0
Other General Plant 1.7 0.4 - - (0.2) 1.9
--------- --------- --------- --------- --------- ---------
Total 603.8 73.9 - 71.0 (4.8) 601.9
--------- --------- --------- --------- --------- ---------
Transmission
Transmission 1,734.6 66.2 - 23.2 4.6 1,782.2
Storage 266.3 11.6 - 1.1 (0.3) 276.5
Other 222.2 20.0 - 13.6 2.8 231.4
--------- --------- --------- --------- --------- ---------
Total 2,223.1 97.8 - 37.9 7.1 2,290.1
--------- --------- --------- --------- --------- ---------
Distribution
Distribution 638.6 54.9 - 7.1 (3.4) 683.0
Other 33.3 7.3 - 3.3 0.3 37.6
--------- --------- ---------- --------- --------- ---------
Total 671.9 62.2 - 10.4 (3.1) 720.6
--------- --------- --------- --------- --------- ---------
Other Energy
Propane 15.0 2.0 - 0.4 (0.1) 16.5
Other 15.7 3.9 - 0.2 (0.1) 19.3
--------- --------- --------- --------- --------- ---------
Total 30.7 5.9 - 0.6 (0.2) 35.8
--------- --------- ---------- --------- --------- ---------
Total Accumulated
Depreciation and Depletion 3,529.5 239.8 - 119.9 (1.0) 3,648.4
========= ========= ========= ========= ========= =========
NOTE:"Other Changes" generally includes reductions for property sold and the
cost of retiring property, offset by salvage on property retired and
miscellaneous items.
105
106
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
ACCUMULATED DEPRECIATION AND DEPLETION OF PROPERTY,
PLANT AND EQUIPMENT Schedule VI
The Columbia Gas System, Inc. and Subsidiaries -----------
Year Ended December 31, 1992 Page 2 of 3
($ in Millions)
Charged to
------------------
Beginning Other Other Ending
Balance Income Accounts Retirements Changes Balance
--------- ------ -------- ----------- ------- -------
Oil and Gas
United States Cost Center 441.3 209.4 (a) - 48.7 0.1 602.1
Other General Plant 10.8 0.6 - 0.7 (9.0) 1.7
--------- --------- ------- --------- --------- ---------
Total 452.1 210.0 - 49.4 (8.9) (b) 603.8
--------- --------- ------- --------- --------- ---------
Transmission
Transmission 1,680.7 65.1 - 10.7 (0.5) 1,734.6
Storage 256.9 10.9 - 1.2 (0.3) 266.3
Other 206.9 19.6 - 2.8 (1.5) 222.2
--------- --------- ------- --------- --------- ---------
Total 2,144.5 95.6 - 14.7 (2.3) 2,223.1
--------- --------- ------- --------- --------- ---------
Distribution
Distribution 594.7 51.5 - 7.2 (0.4) 638.6
Other 29.3 6.1 - 2.7 0.6 33.3
--------- --------- ------- --------- --------- ---------
Total 624.0 57.6 - 9.9 0.2 671.9
--------- --------- ------- --------- --------- ---------
Other Energy
Propane 13.6 1.9 - 0.6 0.1 15.0
Other 12.7 3.0 - 0.1 0.1 15.7
--------- --------- ------- --------- --------- ---------
Total 26.3 4.9 - 0.7 0.2 30.7
--------- --------- ------- --------- --------- ---------
Total Accumulated
Depreciation and Depletion 3,246.9 368.1 - 74.7 (10.8) 3,529.5
========= ========= ======= ========= ========= =========
NOTE:"Other Changes" generally includes reductions for property sold and the
cost of retiring property, offset by salvage on property retired, and
miscellaneous items. Significant items are noted below.
(a) Includes a writedown in the carrying value of the United States Cost
Center ($126.4 million).
(b) Primarily reflects the net transfer of assets from Inland Gas Company (Oil
and Gas - $3.4 million) to Columbia Gas of Kentucky, Inc. and sales of
assets by Columbia Natural Resources, Inc. (Oil and Gas - $5.5 million).
106
107
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
ACCUMULATED DEPRECIATION AND DEPLETION OF PROPERTY,
PLANT AND EQUIPMENT Schedule VI
The Columbia Gas System, Inc. and Subsidiaries -----------
Year Ended December 31, 1991 Page 3 of 3
($ in Millions)
Charged to
------------------
Beginning Other Other Ending
Balance Income Accounts Retirements Changes Balance
--------- ------ -------- ----------- ------- -------
Oil and Gas
United States Cost Center 422.0 82.1 - 54.5 (8.3) 441.3
Canadian Cost Center 118.8 72.3 (a) - - (191.1) (b) -
Other General Plant 2.3 0.9 (0.1) 2.5 10.2 (b,c) 10.8
--------- --------- ------- --------- --------- ---------
Total 543.1 155.3 (0.1) 57.0 (189.2) 452.1
--------- --------- ------- --------- --------- ---------
Transmission
Transmission 1,625.3 63.2 - 10.5 2.7 1,680.7
Storage 246.8 10.6 - 0.6 0.1 256.9
LNG - Cove Point 110.5 (0.9) (0.9) - (108.7) (d) -
Other 200.0 17.5 - 14.9 4.3 206.9
--------- --------- ------- --------- --------- ---------
Total 2,182.6 90.4 (0.9) 26.0 (101.6) 2,144.5
--------- --------- ------- --------- --------- ---------
Distribution
Distribution 569.4 55.3 - 7.4 (22.6) (c,e) 594.7
Other 34.7 5.2 - 2.4 (8.2) (c,e) 29.3
--------- --------- ------- --------- --------- ---------
Total 604.1 60.5 - 9.8 (30.8) 624.0
--------- --------- ------- --------- --------- ---------
Other Energy
Propane 12.6 2.0 - 1.1 0.1 13.6
Other 12.0 2.0 - 1.7 0.4 12.7
--------- --------- ------- --------- --------- ---------
Total 24.6 4.0 - 2.8 0.5 26.3
--------- --------- ------- --------- --------- ---------
Total Accumulated
Depreciation and Depletion 3,354.4 310.2 (1.0) 95.6 (321.1) 3,246.9
========= ========= ======= ========= ========= =========
Note:"Other Changes" generally includes reductions for property sold and the
cost of retiring property, offset by salvage on property retired, and
miscellaneous items. Significant items are noted below.
(a) Includes writedowns to reduce the carrying value of the Canadian Cost
Center ($61.6 million). A portion of the writedown was recorded in
"Cumulative Effect of Change in Accounting for Income Taxes" ($25.2
million) in connection with the adoption of SFAS No. 96.
(b) Includes the sale of Columbia Gas Development of Canada Ltd. in a
transaction completed in January 1992, effective December 31, 1991.
(Canadian Cost Center - $191.1 million and Other General Plant - $1.1
million).
(c) Includes reclassification of certain Inland Gas Company assets from
Distribution properties (Distribution - $5.1 million and Other - $5.4
million) to Oil and Gas properties (Other General Plant $11.3 million).
(d) Reflects the deconsolidation of Columbia LNG Corporation, now recorded as
"Investment in Columbia LNG Corporation".
(e) Includes the sale of Columbia Gas of New York, Inc. in a transaction
completed in April 1991 (Distribution - $14.6 million and Other - $3.0
million).
107
108
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Schedule VIII
-------------
VALUATION AND QUALIFYING ACCOUNTS
The Columbia Gas System, Inc. and Subsidiaries
Year Ended December 31,
($ in Millions)
Additions - Charged to
------------------------
Beginning Other Deductions Ending
Description Balance Income Accounts (a) (b) Balance
- ----------- --------- ------ ------------ ---------- -------
Reserves deducted in the balance sheet
from the assets to which they apply:
Allowance for doubtful accounts
1993 11.8 17.9 12.6 30.5 11.8
1992 9.7 17.9 9.4 25.2 11.8
1991 8.3 18.0 7.6 24.2 9.7
(a) Reflects reclassification to a regulatory asset of the uncollectible
accounts related to the Percent of Income Plan (PIP) of Columbia Gas of
Ohio, Inc.
(b) Principally reflects amounts charged off as uncollectible less amounts
recovered.
108
109
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
SHORT-TERM BORROWINGS (A) Schedule IX
The Columbia Gas System, Inc. and Subsidiaries -----------
($ in Millions) Page 1 of 2
Weighted Maximum Average Weighted
Average Amount Amount Average
Category of Aggregate Balance Interest Outstanding Outstanding Interest Rate
Short-Term at End of Rate at End During the During the During the
Borrowings (a) Period of Period Period Period Period (b)
- ----------------------- ------ --------- ------ ------ ----------
December 31, 1993
Commercial Paper (In Default) (a) (a) (a) (a) (a)
Bank Loans (In Default) (a) (a) (a) (a) (a)
Debtor-In-Possession
Financing (Corporation) (c) - - - - -
Debtor-In-Possession
Financing (Columbia
Transmission) (c) - - - - -
December 31, 1992
Commercial Paper (In Default) (a) (a) (a) (a) (a)
Bank Loans (In Default) (a) (a) (a) (a) (a)
Debtor-In-Possession
Financing (Corporation) (c) - - 136.0 6.6 7.3%
Debtor-In-Possession
Financing (Columbia
Transmission) (c) - - - - -
December 31, 1991
Commercial Paper (In Default) (d) (a) (a) 362.0 231.5 7.0%
Bank Loans (In Default) (d) (a) (a) 630.0 497.5 7.4%
Debtor-In-Possession
Financing (Corporation) (c) 136.0 7.2% 173.0 91.5 8.0%
Debtor-In-Possession
Financing (Columbia
Transmission) (c) - - 5.4 3.7 9.9%
(a) Prior to June 19, 1991, certain working capital requirements of the
Corporation and its subsidiaries were met through the sale of commercial
paper, through notes sold directly to commercial banks and/or through
borrowings under bank lines of credit. The commercial paper was sold
through dealers with maturities ranging from one day to nine months. The
Corporation maintained a $500 million revolving short-term committed line
of credit, for which participating banks were paid fees of 1/8% per annum
on the total facility and 1/16% per annum on the unused portion of the
facility. In addition, a $750 million revolving
109
110
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
SHORT-TERM BORROWINGS (A) Schedule IX
The Columbia Gas System, Inc. and Subsidiaries -----------
($ in Millions) Page 2 of 2
subordinated committed line of credit was maintained, for which
participating banks were paid 3/8% per annum on the unused portion of the
facility. Loans under the lines of credit bore interest according to
rate options based on prime, bank certificates of deposit or the London
InterBank Offered Rate. Since its Chapter 11 filing, the Corporation has
had $266.5 million of commercial paper and $621 million of bank loans in
default under these facilities.
For periods subsequent to the Chapter 11 filings, Debtor-In-Possession
(DIP) Financing facilities were established by the Corporation and
Columbia Transmission. The Corporation has available up to $100 million,
reduced from $200 million on June 18, 1993, under its DIP Financing
facility. Borrowings are at the agent's per annum alternate reference
rate plus 1% or the Eurodollar Rate plus 2-1/4% (for either 1, 2 or 3
months). Also, the Corporation is subject to a commitment fee of
one-half of 1% per annum on the average daily unused amount of the
facility. Additionally, Columbia Transmission's separate DIP facility
initially of up to $80 million was reduced to $25 million, on November
29, 1991, which is only available for the issuances of Letters of Credit.
Borrowings were at the agent's per annum alternate reference rate plus
1-1/2% or the Eurodollar Rate plus 2-3/4% (for either 1, 2 or 3 months).
Columbia Transmission is also subject to a commitment fee of one-half of
1% per annum on the average daily unused amount of the facility.
For additional information regarding these DIP facilities, reference is
made to pages 51 and 52 of Management's Discussion and Analysis in Item 7
and Note 10 in Item 8 on page 83. Reference is also made to the DIP
Financing Exhibits 10-BR, 10-CB, 10-CC, 10-CD, 10-CF, 10- CG, 10-CH,
10-CK and 10-CL included or incorporated by reference, in this filing.
(b) Based on actual interest expense divided by the average daily borrowings
outstanding during the period.
(c) The Corporation did not have any amounts outstanding under its DIP
facility during 1993. However, the Corporation's facility was used
during the periods January 1, 1992 through December 31, 1992 and August
20, 1991 through December 31, 1991. Columbia Transmission did not have
any amounts outstanding under its DIP facility during 1993 and 1992.
However, the facility was used during the period of August 6, 1991
through August 21, 1991. Both the Corporation's and Columbia
Transmission's DIP facilities include the availability of letters of
credit of up to $50 million and $25 million, respectively. As of
December 31, 1993, $12.8 million and $1.8 million of letters of credit
were outstanding under the Corporation's and Columbia Transmission's DIP
facilities, respectively.
(d) The period used in calculating the amounts for short-term financing was
from January 1, 1991 through June 18, 1991. This period represents the
time during which the Corporation was not in default of its loan
agreements.
110
111
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Schedule X
----------
SUPPLEMENTARY INCOME STATEMENT INFORMATION
The Columbia Gas System, Inc. and Subsidiaries
($ Millions)
Charged to Costs and Expenses
----------------------------------------------------------
Item 1993 1992 1991
- ------------------------------------------ ---- ---- ----
Maintenance and repairs 165.5 157.1 120.8
Taxes other than payroll and
income taxes:
Property taxes 76.0 80.5 82.2
Gross receipts taxes 81.3 73.9 72.5
Depreciation and amortization of intangible assets, pre-operating costs and
similar deferrals, royalties and advertising costs have been omitted inasmuch
as the amounts are not in excess of one percent of total revenues as reported
in the Statements of Consolidated Income.
111
112
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
There has not been a change of accountants nor any disagreements concerning
accounting and financial disclosure within the past two years.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information required by this item is contained in the Corporation's Proxy
Statement related to the 1993 Annual Meeting of Stockholders, filed pursuant
to Section 14 of the Securities Exchange Act of 1934 and is incorporated herein
by reference.
Information regarding the System's executive officers, who are elected annually
by the directors, is as follows:
The Columbia Gas System, Inc.
JOHN H. CROOM, 61, Chairman of the Board, President and Chief
Executive Officer of the Corporation since August 1984.
DANIEL L. BELL, JR., 64, Senior Vice President and Chief Legal
Officer of the Corporation since January 1989, Corporate Secretary
since January 1988. Senior Vice President of Columbia's Service
Corporation since September 1979.
LOGAN W. WALLINGFORD, 61, Senior Vice President of Columbia Gas
System Service Corporation since March 1989. Senior Vice
President of Planning and Storage for Columbia Transmission from
July 1988 to February 1989, Senior Vice President, Gas Acquisition
from July 1987 to June 1988, Vice President of Planning from March
1985 to June 1987.
RICHARD E. LOWE, 53, Vice President of the Corporation and
Columbia Gas System Service Corporation since September 1988.
Vice President and General Auditor of Columbia Gas System Service
Corporation from April 1987 to August 1988. Treasurer of Columbia
Gas Development Corporation from April 1979 to March 1987.
JAMES P. HOLLAND, 45, Chairman and Chief Executive Officer of
Columbia Transmission and Columbia Gulf Transmission Company since
September 1990. President of Columbia Transmission from May 1988
to August 1990. President of Columbia Gulf Transmission Company
from October 1989 to August 1990. Senior Vice President of
Marketing of Columbia Transmission from July 1987 to April 1988,
Senior Vice President of Gas Procurement from January 1986 to June
1987.
C. RONALD TILLEY, 56, Chairman and Chief Executive Officer of
Columbia Distribution Companies since January 1987.
MICHAEL W. O'DONNELL, 49, Senior Vice President and Chief
Financial Officer of the Corporation since October 1993. Senior
Vice President and Assistant Chief Financial Officer of the
Columbia Gas System Service Corporation since 1989.
112
113
ITEM 11. EXECUTIVE COMPENSATION
Information required by this item is contained in the Corporation's Proxy
Statement related to the 1993 Annual Meeting of Stockholders, filed pursuant to
Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by
reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required by this item is contained in the Corporation's Proxy
Statement related to the 1993 Annual Meeting of Stockholders, filed pursuant to
Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by
reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by this item is contained in the Corporation's Proxy
Statement related to the 1993 Annual Meeting of Stockholders, filed pursuant to
Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by
reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Exhibits
Reference is made to pages 116 through 120 for the list of exhibits filed as a
part of this Annual Report on Form 10-K.
Pursuant to Item 601(b), paragraph (4)(iii)(A) of Regulation S-K, certain
instruments representing long-term debt of the Corporation or its subsidiaries
have not been included as Exhibits because such debt does not exceed 10% of the
total assets of the Corporation and its subsidiaries on a consolidated basis.
The Corporation agrees to furnish a copy of any such instrument to the SEC upon
request.
Financial Statement Schedules
All of the financial statements and financial statement schedules filed as a
part of the Annual Report on Form 10-K are included in Item 8.
Reports on Form 8-K
A report on Form 8-K was filed on November 18, 1993, discussing the retirement
of Mr. John D. Daly, executive vice president of The Columbia Gas System, Inc.
and Columbia Gas System Service Corporation effective December 1, 1993.
A report on Form 8-K was filed on January 3, 1994, discussing the Bankruptcy
Court's approval of the extension to March 22, 1994, that Columbia Transmission
and the Corporation have the exclusive right to file Chapter 11 plans of
reorganization.
A report on Form 8-K was filed on January 19, 1994, discussing Columbia
Transmission's filing of its Chapter 11 Reorganization Plan with the Bankruptcy
Court.
A report on Form 8-K was filed on February 14, 1994, containing a Press Release
published on February 10, 1994, regarding the financial and operating results
for the year ended December 31, 1993.
113
114
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Continued)
Undertaking made in Connection with 1933 Act Compliance on Form S-8
For purposes of complying with the amendments to the rules governing Form S-8
under the Securities Act of 1933, the Corporation undertakes the following,
which is incorporated by reference into the registration statements on Form
S-8, Nos. 33-10004 (filed November 26, 1986) and 33- 42776 (filed September 13,
1991):
Insofar as indemnification for liabilities arising under the Securities Act of
1933 (Act) may be permitted to directors, officers and controlling persons of
the registrant pursuant to the foregoing provisions, or otherwise, the
registrant has been advised that in the opinion of the Securities and Exchange
Commission such indemnification is against public policy as expressed in the
Act and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the
registrant of expenses incurred or paid by a director, officer or controlling
person of the registrant in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling person in
connection with the securities being registered, the registrant will, unless in
the opinion of its counsel the matter has been settled by controlling
precedent, submit to a court of appropriate jurisdiction the questions whether
such indemnification by it is against public policy as expressed in the Act and
will be governed by the final adjudication of such issue.
114
115
SIGNATURES
----------
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
THE COLUMBIA GAS SYSTEM, INC.
-----------------------------
(Registrant)
Dated: March 11, 1994
By: /s/ M. W. O'Donnell
----------------------------------------
(M. W. O'Donnell)
Senior Vice President and
Chief Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
- ----------------------------------------------------------------------------------------------------------------------
Signature Title Date
- ----------------------------------------------------------------------------------------------------------------------
/s/ M. W. O'Donnell (Principal March 11, 1994
------------------------- Financial Officer)
(M. W. O'Donnell)
JOHN H. CROOM Director (Principal March 11, 1994
Executive Officer) ]
R. E. LOWE Vice President (Principal
Accounting Officer) ] March 11, 1994
ROBERT H. BEEBY Director ]
THOMAS S. BLAIR Director ]
WILSON K. CADMAN Director ]
JOHN D. DALY Director ]
SHERWOOD L. FAWCETT Director ]
JAMES P. HEFFERNAN Director ]
ROBERT H. HILLENMEYER Director ]
MALCOLM T. HOPKINS Director ]
W. FREDERICK LAIRD Director ] By:/s/ M. W. O'Donnell
] -------------------
WILLIAM E. LAVERY Director ] (M. W. O'Donnell)
GEORGE P. MACNICHOL,III Director ] Attorney-in-Fact
GERALD E. MAYO Director ]
ERNESTA G. PROCOPE Director ]
JAMES R. THOMAS II Director ]
WILLIAM R. WILSON Director ]
115
116
EXHIBIT INDEX
-------------
Reference is made in the two right-hand columns below to those
exhibits which have heretofore been filed with the Commission. Exhibits so
referred to are incorporated herein by reference.
Reference
------------------
File No. Exhibit
-------- -------
3-A - Restated Composite Certificate of Incorporation, 1-1098 3-A
as amended to October 19, 1988; corrected
copy as of July 15, 1991.
3-B - By-Laws of the Corporation, as amended to 1-1098 3-B
November 18, 1987.
4-A - Indenture, dated as of June 1, 1961, between 1-1098 2-C
the Corporation and Morgan Guaranty Trust
Company of New York, Trustee, and thirteen
supplemental indentures thereto.
4-B - Fourteenth Supplemental Indenture, dated as 2-38139 2-P
of April 1, 1970, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
4-C - Fifteenth Supplemental Indenture, dated as of 2-393340 2-D
October 1, 1970, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
4-D - Sixteenth Supplemental Indenture, dated as of 2-41557 2-E
March 1, 1971, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
4-E - Indenture, dated as of June 1, 1961, between 1-1098 4-E
the Corporation and Morgan Guaranty Trust
Company of New York, Trustee, and the
Seventeenth through the Twenty-eighth
supplemental indentures thereto.
4-H - Twenty-ninth Supplemental Indenture, dated as 1-1098 4-H
of June 1, 1982, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
4-I - Thirtieth Supplemental Indenture, dated as of 1-1098 4-I
January 8, 1986, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
4-J - Thirty-first Supplemental Indenture, dated 1-1098 4-J
August 1, 1986, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
4-K - Thirty-second Supplemental Indenture, dated 1-1098 4-K
August 1, 1986, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
116
117
EXHIBIT INDEX (Continued)
Reference
------------------
File No. Exhibit
-------- -------
4-L - Thirty-third Supplemental Indenture, dated 1-1098 4-L
June 1, 1987, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
4-M - Thirty-fourth Supplemental Indenture, dated 1-1098 4-M
November 1, 1988, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
4-N - Thirty-fifth Supplement Indenture, dated 1-1098 4-N
August 18, 1989, between the Corporation
and Morgan Guaranty Trust Company of
New York, Trustee.
4-0 - Thirty-sixth Supplemental Indenture, dated 1-1098 4-0
November 30, 1989, between the Corporation
and Morgan Guaranty Trust Company of
New York, Trustee.
4-P - Thirty-seventh Supplemental Indenture, dated 1-1098 4-P
June 6, 1990, between the Corporation and
Morgan Guaranty Trust Company of New York,
Trustee.
10-P(a) - Pension Restoration Plan of The Columbia Gas 1-1098 10-P
System, Inc., amended October 9, 1991.
10-Q(a) - Thrift Restoration Plan of The Columbia Gas 1-1098 10-Q
System, Inc. dated January 1, 1989.
10-S - Gas Sales Contract, dated November 15, 1983, 1-1098 10-S
between Tennessee Gas Pipeline Company and
Columbia Gas Transmission Corporation.
10-T* - Agreement and Bridge Agreement dated
December 1, 1993, between Columbia Gas
Transmission Corporation and Consol
Pennsylvania Coal Company.
10-U* - Stipulation dated October 1, 1993, between
Columbia Gas Transmission Corporation and
Tennessee Gas Pipeline Company.
10-V* - Stipulation dated August 24, 1993 between
Columbia Gas Transmission Corporation and
Texas Eastern Transmission Corporation.
10-Z - Amendment, dated as of February 4, 1985, 1-1098 10-Z
to Gas Sales Contract, dated November 15,
1983, between Tennessee Gas Pipeline
Company and Columbia Gas Transmission
Corporation.
10-AN - Indenture of Mortgage and Deed of Trust by 1-1098 10-AN
Columbia Gas Transmission Corporation to
Wilmington Trust Company, as Trustee, dated
August 30, 1985.
- ---------------
(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
*Filed herewith
117
118
EXHIBIT INDEX (Continued)
Reference
------------------
File No. Exhibit
-------- -------
10-AZ(a) - The Columbia Gas System, Inc. Long-Term 1-1098 10-AZ
Incentive Plan, amended through January 1,
1987.
10-BB(a) - Annual Incentive Compensation Plan of 1-1098 10-BB
The Columbia Gas System, Inc., dated
November 16, 1988.
10-BD - $500 million Credit Agreement, dated October 5, 1988 1-1098 10-BD
between the Corporation and Morgan Guaranty
Trust Company of New York, as Agent.
10-BG - Letter Agreement, dated February 15,1989, 1-1098 10-BG
between Texas Gas Transmission Corporation
and Columbia Gas Transmission Corporation,
amending the Letter Agreement of
September 12, 1988.
10-BH - Letter Agreement, dated June 15, 1989, between 1-1098 10-BH
Tennessee Gas Pipeline Company and
Columbia Gas Transmission Corporation.
10-BI - Amended and Restated Credit Agreement, dated 1-1098 10-BI
September 17, 1990, between the Corporation
Morgan Guaranty Trust Company of New York,
as Agent.
10-BJ - Gas Sales Contract, dated September 1, 1989, 1-1098 10-BJ
between Tennessee Gas Pipeline Company and
Columbia Gas Transmission Corporation.
10-BK - Gas Sales Contract, dated January 1,1989, 1-1098 10-BK
between Tennessee Gas Pipeline Company,
and Columbia Gas Transmission Corporation.
10-BL - Service Agreement, dated November 1, 1989, 1-1098 10-BL
between Transcontinental Gas Pipe Line
Corporation and Columbia Gas Transmission
Corporation.
10-BR - Secured Revolving Credit Agreement dated 1-1098 10-BR
September 23, 1991, between The Columbia
Gas System Inc. and Manufacturers Hanover Trust
Company, as Agent.
10-BU - Share Sale and Purchase Agreement between The 1-1098 10-BU
Columbia Gas System, Inc. and Anderson Exploration
Ltd. dated November 25, 1991.
10-BV - Security Agreement dated as of January 15, 1992, 1-1098 10-BV
between The Columbia Gas System, Inc. and
Anderson Exploration Ltd. and Montreal Trust
Company of Canada.
- ---------------------------
(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
118
119
EXHIBIT INDEX (Continued)
Reference
------------------
File No. Exhibit
-------- -------
10-BW - Kotaneelee Litigation Indemnity Agreement made 1-1098 10-BW
as of December 31, 1991, among The Columbia
Gas System, Inc. and Columbia Gas Development
of Canada Ltd. and Anderson Exploration Ltd.
10-BX - Specified Litigation Indemnity Agreement made 1-1098 10-BX
as of December 31, 1991, among The Columbia
Gas System, Inc. and Columbia Gas Development
of Canada Ltd. and Anderson Exploration Ltd.
10-BY(a) - Columbia Gas Restoration Security Trust 1-1098 10-BY
Agreement dated June 1, 1991 with Dauphin
Deposit Bank and Trust Company.
10-BZ(a)* - Employment Agreements between The Columbia Gas
System, Inc. and seven senior executives, each
dated July 19, 1993.
10-CA(a) - The Columbia Gas System, Inc. Retirement Plan 1-1098 10-CA
for Outside Directors, as amended, August 21, 1991.
10-CB - First Amendment, dated as of October 21, 1991, to the 1-1098 10-CB
Secured Revolving Credit Agreement, dated as of
September 23, 1991, among The Columbia Gas System,
Inc., certain banks party thereto and Manufacturers
Hanover Trust Company as Agent for the banks.
10-CC - Second Amendment, dated as of December 11, 1991, to 1-1098 10-CC
the Secured Revolving Credit Agreement, dated as of
September 23, 1991, among The Columbia Gas System,
Inc., certain banks party thereto and Manufacturers
Hanover Trust Company as Agent for the banks.
10-CD - Amended and Restated Secured Revolving Credit Agreement, 1-1098 10-CD
dated April 2, 1992, between Columbia Gas Transmission
Corporation and Manufacturers Hanover Trust Company
as Agent for banks.
10-CE - Settlement Agreement, dated September 17, 1992, among 1-1098 10-CE
The Columbia Gas System, Inc., Columbia LNG Corporation,
Shell LNG Company, Shell Oil Company, R. J. Pusanik,
L. L. Smith, J. B. Edrington and D. E. Cannon, in
settlement of Columbia LNG., et al. v. Shell LNG Co.,
et. al., Civil Action No. 12663 in the Court of
Chancery of the State of Delaware.
10-CF - Amended and Restated Security Agreement, dated as of 1-1098 10-CF
April 2, 1992, between Columbia Gas Transmission
Corporation and Manufacturers Hanover Trust Company.
10-CG - Third Amendment, dated June 15, 1992, to the Secured 1-1098 10-CG
Revolving Credit Agreement, dated as of September 23, 1991
(as therefore amended), among The Columbia Gas System, Inc.,
certain banks party thereto and Manufacturers Hanover Trust
Company, as Agent for the banks.
- ---------------------------
(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
*Filed herewith.
119
120
EXHIBIT INDEX (Continued)
Reference
------------------
File No. Exhibit
-------- -------
10-CH - First Amendment, dated as of January 8, 1993, to the 1-1098 10-CH
Amended and Restated Secured Revolving Credit Agreement,
dated as of April 2, 1992 between Columbia Gas Transmission
Corporation and Chemical Bank.
10-CI(a)* - Retention Agreement between The Columbia Gas System, Inc. and Logan
W. Wallingford dated July 19, 1991.
10-CJ* - Amended and Restated Agreement of Cove Point
LNG Limited Partnership between Columbia LNG and
PEPCO Energy Company, Inc. dated January 27, 1994.
10-CK* - Fourth Amendment, dated April 26, 1993, the Secured Revolving
Credit Agreement, dated as of September 23, 1991 (as therefore
amended), among The Columbia Gas System, Inc., certain bank parties
thereto and Chemical Bank successor by merger to Manufacturers
Hanover Trust Company as agent for the banks.
10-CL* - Second Amendment, dated December 9, 1993, to the Amended and
Restated Secured Revolving Credit Agreement, dated as of
April 2, 1992 between Columbia Gas Transmission Corporation
and Chemical Bank.
10-CM* - Plan of Reorganization for Columbia Gas Transmission Corporation
as filed with the United States Bankruptcy Court for the District
of Delaware on January 18, 1994.
11* - Statements Re Computation of Per Share Earnings.
12* - Statements of Ratio of Earnings to Fixed Charges
and Preferred Stock Dividends.
21* - Subsidiaries of The Columbia Gas System, Inc.
23-A* - Letter report, dated January 24, 1994, and
the written consent to the filing and use of
information contained in such letter report,
Reports and Registration Statements filed
during 1994, of Ryder Scott Company Petroleum Engineers,
independent petroleum and natural gas consultants
23-B* - Written consent to the filing and use of information
contained in the letter report, dated January 5, 1994,
in Reports and Registration Statements filed during 1994,
of McDaniel & Associates Consultants Ltd., independent
petroleum and natural gas consultants.
23-C* - Written consent of Arthur Andersen & Co.,
independent public accountants, to the
incorporation by reference of their report
included in the 1993 Annual Report on Form
10-K of The Columbia Gas System, Inc. and
their report included in The Columbia Gas
System, Inc.'s 1993 Annual Report to Shareholders
in the registration statements on Form S-8
(File No. 33-10004), and Form S-8
(File No. 33-42776).
24* - Powers of attorney and certified copy of board resolution authorizing execution of Form 1O-K
by power of attorney.
- --------------------------
(a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
*Filed herewith.
120